Closing the Gap · (Chrysaor) Stuart Duncanson (Doosan Babcock), Stephen Cunniffe (Doosan Babcock),...
Transcript of Closing the Gap · (Chrysaor) Stuart Duncanson (Doosan Babcock), Stephen Cunniffe (Doosan Babcock),...
Closing the GapTechnology for a Net Zero North Sea
September 2020Full Report
Acknowledgements The team that researched and prepared this report was led by Malcolm Forbes-Cable and included Amy Bowe, David Linden and Kristina Beadle from Wood Mackenzie, and Samhitha Udupa, Arnold Bos, Oscar Gámez and Başak Çınlar from Lux Research.
In-house sector experts:Wood Mackenzie: Peter Martin, Benjamin Gallagher, Søren Lassen, Shimeng Yang, Dan Eager, Shashi Barla, Shane Murphy, Sandra Smith. Lux Research: Arij van Berkel, Michael Holman, Holly Havel.
The project team were supported and advised by the OGTC team:Led by Martyn Tulloch with the support of Jason Paterson, Hayleigh Pearson, Emma Swiergon, Dr Vinay Mulgundmath, Neil Wilkinson and Caragh McWhirr.
Industry experts interviewed for the report:Myrtle Dawes (OGTC), Luca Corradi (OGTC), Gillian White (OGTC), Graeme Rogerson (OGTC), Stuart Young (ABB), Roy Stenhouse (Aker Solutions), Kjartan Pedersen (Aker Solutions), Sam Coupland (BP), James Lawson (Chrysaor), Robert Barrie (Chrysaor), Graeme Wilson (Chrysaor) Stuart Duncanson (Doosan Babcock), Stephen Cunniffe (Doosan Babcock), Professor Stuart Haszeldine (Edinburgh University), Professor Mercedes Maroto-Valer (Heriot-Watt University), Chris Ayers (OPEX Group), Martin McCormack (Opportunity Northeast), Andy Rodden (Opportunity Northeast), Ralph Torr (ORE Catapult), Hugh Riddell (ORE Catapult), Steve Murphy (Pale Blue Dot Energy), Nigel Holmes (Scottish Hydrogen and Fuel Cell Association), Robert Cullen (Shell), Matthew Knight (Siemens), Robert Stephen (Siemens), Katie Abbott (Total), Tara Schmidt (Wood), Martyn Link (Wood), Keith Anderson (Wood), Alan Mortimer (Wood).
Production and design team:Wood Mackenzie: Craig Unsworth, Ross Pollock, Steve Robertson-Pool, Pari Karani, Katrina Melvin, Susan McGurk.
The OGTC would like to thank the Scottish Government and Chrysaor for contributing to this study as core funding partners.
Foreword
In recent months, much has been written about the need to accelerate the transition to a lower carbon and ultimately net zero energy system. Big companies have pivoted their strategies, regulators have set out their visions of the future and governments have provided targeted support. Now we need to make it happen and technology is critical.
At the OGTC, our mission is to develop and deploy technologies that enable a net zero energy system, investing alongside companies, governments and innovators. We’re focused on supporting the oil and gas sector as it transitions to a net zero future, recognising how critical its expertise is for the net zero energy system, and working with a range of other sectors from renewables and marine to defence and aerospace.
We try to be holistic in our approach, creating alliances and partnerships to tackle big technology challenges. This study provides valuable insights to help identify the key innovation gaps, shape our roadmap and projects and direct our future investment. There are several clear areas that need to be unlocked.
We need to invest in technologies that reduce oil and gas operational emissions. Creating offshore power grids and infrastructure to electrify platforms is critical – both power from shore and from offshore wind. At the same time, new solutions are required to prevent routine venting and flaring, and significantly reduce methane leaks.
With the rapid growth of fixed-bottom offshore wind power, the UK has become world-leader in offshore power production, but we have not capitalised on the investment in job creation or manufacturing capability. To become the leader in floating offshore wind technology we must seize the opportunity to build design, manufacturing and installation capability, to standardise turbine design, invest in a next generation of transmission infrastructure and pioneer new energy storage solutions.
There’s a lot of talk about the UK becoming a hydrogen economy but progress has been painfully slow. We need to accelerate new technologies that effectively halve the cost of hydrogen – solutions to separate hydrogen from carbon dioxide for blue hydrogen and saltwater electrolysis for green hydrogen generation offshore alongside wind farms.
For carbon capture, utilisation and storage, the real challenge is the lack of a feasible commercial model. However, technology can help with the economics. We need to tackle the technology risks, innovate to cut the costs of existing technology and look for new incremental solutions to increase the pace of deployment.
Reimagining the North Sea as an integrated energy system is essential for the UK and Scotland to achieve their net zero ambitions. But we need to invest now to close the gap on the key technologies needed to make this ambition a reality. We need to partner cross sector and share our skills and capabilities for the greater good of the UK.
With decades of energy expertise this country has a huge opportunity to become a leading manufacturer, designer, installer and operator of next generation energy systems. This is where governments and industry should focus investment at pace in the coming years.
Colette Cohen OBECEO, The OGTC
Solutions that deliver incremental improvements are always valuable, but with less than 30 years left to achieve our net zero goals, it is critical we focus on the big priorities – and move fast. So, this study focused on identifying the technologies that would really move the dial to create a net zero North Sea.
Executive SummaryThe unique attributes of the UK Continental Shelf (UKCS) and the UK’s advanced energy sector give the region a head start in developing net zero industries. Investing in low carbon technologies and establishing an integrated energy system will be pivotal to achieving the legally binding net zero 2050 target for the UKCS and the wider economy.
As the UKCS transitions, oil and gas will naturally deplete, but this will be more than offset by growth in offshore renewables, hydrogen and carbon capture, utilisation and storage (CCUS). This could more than double the economic impact of the UKCS, contributing £2.5 trillion to the UK economy and creating over 200,000 new jobs.
Creating an integrated energy system on the UKCS requires investment of £430 billion, with £270 billion expected to be spent in the UK. Over the next 15 years, the investment profile is dominated by oil and gas and offshore wind, each requiring £75 billion in capital investment, around half of which is expected to be spent in the UK.
As climate change policy progresses not only in the UK, but also in Europe and further afield, there will be an increasing number of opportunities for the UK to export low carbon technologies, products and expertise, emulating the success of the oil and gas sector. To realise this opportunity we need to invest with pace.
Key findings Blue hydrogen can play a key role, especially if existing technology can be enhanced
Blue hydrogen needs improved yield and enhanced CO2 capture efficiency to make it commercially viable, with opportunities to innovate in both hydrogen membranes and CO2 sorbents. Alternatively, novel hydrogen concepts such as plasma-based processes may offer disruptive solutions.
Technological innovation will be critical to reduce the cost of green hydrogen generation
Developing cost-effective saltwater electrolysis technology is essential to unlocking the potential of green hydrogen. Producing durable electrolyser catalysts materials and creating combined subsea electrolysis and compression systems are areas of particular promise.
Hydrogen transportation and storage offer opportunities to leverage oil and gas knowledge
Repurposing the existing offshore pipeline network to convey hydrogen offers opportunities to develop innovative pipeline re-lining techniques and leak detection devices, while underground storage in either salt caverns or depleted hydrocarbon fields requires research across many areas, including reservoir rock reactivity and modelling hydrogen migration through water-filled porous media.
Hydrogen fuel cells could be used to provide low carbon power to offshore assets
Fuel cells could help to power field production operations if provided with a sufficient fuel supply or a connection to nearby hydrogen pipelines. To make this efficient, fuel cell catalyst materials need to be made more durable and less costly and fuel cell manufacturing techniques need to be optimised.
Significantly reducing the cost of carbon capture technology will drive growth and scale
Reducing the cost and improving the efficiency of carbon capture technologies, from the solvents and sorbents to membranes and conversion solutions, will improve feasibility and could also lead to more scalable, accessible direct capture technology.
CO2 storage requires innovation across many fronts
To fully realise the CO2 storage potential of the UKCS, technological innovation is needed to better model and understand CO2 behaviour after injection. Developing compact CO2 processing plants and subsea separation and injection equipment offers opportunities to drive down costs, while the disruptive potential of numerous carbon utilisation technologies should not be overlooked.
Other renewable energy technologies could have a role to play on the UKCS
Technological innovation is essential if the abundant wave and tidal resource available across the UKCS is to be harnessed. In marine energy, innovation is required to develop economically feasible power take off technologies and foundations and support systems; in floating solar, enhancing existing systems to cope with harsh UKCS conditions could add another option in the UKCS renewable energy portfolio.
Understanding and managing interdependencies is critical to creating a net zero UKCS
Delivery of an integrated UKCS energy system has many critical interdependencies, and a clear and cohesive strategy is needed to ensure that technological innovation, regulation and policy are aligned and harmonised. Additionally, digital technologies need to be leveraged across the oil and gas, renewables, hydrogen and CCUS sectors in order to create an efficient and coordinated integrated energy system on the UKCS.
More investment is needed in oil and gas emissions reduction technology
Additional investment is required to make oil and gas operations more efficient and reduce emissions. The key innovation gaps are in platform electrification, methane leak detection and prevention, flaring mitigation and advanced subsea developments.
Offshore wind will make a massive contribution, but technology innovation is still required
While fixed wind is expected to play a crucial role in meeting the country’s net zero targets, significant opportunity remains to innovate across many areas including developing larger blades and taller towers, automated inspection technology and innovative recycling and decommissioning options.
UK must tackle innovation gaps to become a global leader in floating offshore wind
The UK can become a global leader in floating offshore wind but critical innovation gaps such as robust dynamic cabling and mooring systems must be addressed to unlock this potential. Optimising and standardising floating wind foundation designs with a specific focus on UKCS meteorological and bathymetric conditions will be crucial if the full potential of the basin’s offshore wind resource is to be harnessed.
2020 2035 2050
Short-term Mid-term Long-term
H2
H2
Source: Wood Mackenzie, Lux Research
Integrated energy system
UKCS technologies: roadmap to achieving a net zero integrated energy system
Renewable power
Affordable energy
Clean fuels Low-carbon petrochemical
feedstocks
Long-term carbon
sequestration
Low-carbon technologies and
supply chain
££
Continued fixed- bottom build out
Blue hydrogen pilot production
CCUS pilot projects
Platform electrification
Turbine clean fuel adaptation/e-motor use
Direct power: wind farms to O&G platforms
Growth in deployment of
floating wind farms
Green hydrogen pilot production
Integrated capture in industrial clusters
Saltwater electrolysis: offshore
H2 production
Development of high capacity CO2 capture materials
Repurposing of O&G infrastructure for H2 and CO2 networks
Reusable small pools production systems
Subsea factory developments
Direct air capture of residual CO2
emissions
CO2 utilisation scales up
Offshore energy storage at scale
Commercial scale marine energy
Optimisation-led operational emissions reduction
Flexible transmission infrastructure for offshore network
UKCS integrated energy vision 2050Industrial Cluster
Petrochemical cluster
Hydrogen power plant
Domestic supply
Electrified FPSO
Power plant with CO2 storage
Hydrogen production with CO2 capture
Energy storage
Small pools reusable production system
Electrified platform
CO2 injection facility
Wind with built in electrolysers (green hydrogen)
Wind powering hydrogen production facility
Export interconnector
Energy hub
Subsea/floating substations
CO2 injection facility
CO2 direct air capture
CO2 utilisationElectrolyser plant (green hydrogen)
Mobile floating wind unit
Offshore operations control center
Repurposed pipeline
CO2 transport
Hydrogen transportGreen hydrogen production facility
Energy storage
Subsea development Subsea factory
Surface production system
Floating wind
• Platformelectrification,methaneleakagedetectionandflaringmitigation will be key for emissions reduction.
• £80 billion of capital investment* will be spent in the UK between 2020-2050 to ensure production targets are met and offshore emissions are reduced.
• The offshore oil and gas industry could have a total economic impact of £900 billion on the UK economy between 2020 and 2050.
Oil and gas
• Abundantwindpotentialandsignificantdevelopmentmomentummeans offshore wind is on track to meet the CCC’s target.
• Achieving the 75 GW 2050 target will result in £60 billion of capex* being invested in UK industries such as construction.
• By 2050, the offshore renewables industry could support 150,000 jobs and have generated an economic impact of £600 billion.
Offshore Renewables
• Challenges around hydrogen transport and storage need to be overcome to allow a hydrogen economy to develop.
• Over £70 billion of UK based capital investment* is required to meet the CCC’s target of 270 TWh of hydrogen demand in 2050.
• Development of a hydrogen economy could support more than 100,000 jobs in 2050 and have a total economic impact of £800 billion between now and 2050.
• The biggest barrier to CCUS development is the lack of feasible business model.
• Upwards of £60 billion of UK capital investment* is needed to meet the CCC’s 176 MtCO2/yr CO2 capture and storage target.
• The CCUS industry could generate a total economic impact of £200 billion between 2020 and 2050 and create 15,000 new jobs.
• Over 200,000 new jobs could be created across the UK through the growth of offshore renewables, hydrogen and CCUS.
• Over £430 billion of capex is required between 2020 and 2050 to meet the CCC and OGUK targets, the UK content of this is expected to be around £270 billion.
• An integrated UKCS energy system could generate £36 billion per year in revenue by 2050 through the domestic sale of products and services.
Hydrogen
CCUS
Economic Impact
£
*UK content of capital investment. For full capex see section 6.1.
Schematic view of what an integrated UKCS energy system could look like in 2050
Requirements and benefits of achieving an integrated net zero UKCS
Technology Challenges
Offshore power grid managementIntegrating offshore wind developments with existing and planned offshore oil and gas operational power demand via interconnected infrastructure could enable the critical electrification of oil and gas installations, while at the same
time facilitating stable low-carbon electricity supply to the National Grid. Power grid costs can be shared between oil and gas, wind farm, energy storage and transmission operators. However, to unlock this prize, technological innovation is required at both system and individual technology level.
Short-term challenges Long-term challenges
CCUSWhile coordinated financial and policy support will be necessary to create favourable conditions to kick-start the CCUS industry, reducing the cost of carbon capture, transportation and storage technology will be essential
to ensuring that the costs of implementing CCUS are minimised. Today’s high capex costs associated with the development of CO2 capture, transportation and storage infrastructure offer many opportunities for both evolutionary and disruptive innovation.
Hydrogen innovationFor hydrogen to play a key role in reaching net zero targets, a hydrogen supply chain needs to be in development before 2035. This requires a concerted and coordinated effort to develop economically viable solutions across the
end-to-end hydrogen economy – from production, though transport and storage, to end use. The opportunity to develop blue and green hydrogen production technologies, alongside novel transportation and storage solutions, offers an unparalleled opportunity for the supply chain to seize a position at the vanguard of this nascent international market.
In order to stimulate demand, there is a need for clear incentives for low-carbon hydrogen in order to develop sufficient demand in onshore industries, including transportation, domestic or industrial heating, or even hydrogen or CO2 derived materials, chemicals and fuels.
DigitalisationA reliable and connected data infrastructure, combined with widespread use of data analytics and control, will be essential for the efficient delivery of low carbon energy from the UKCS. Digital technologies will initially promote
operational and energy efficiency. As an integrated energy system develops, unmanned and autonomous digital facilities within each industry will need to be connected. This requires ensuring data interoperability across the different components in the energy system and strong communication infrastructure. Maintaining the highest possible level of cyber security between assets and operations centres onshore will remain critical tasks in any digital system.
Energy hubsEnergy hubs which combine operation, production, storage and transport of the four energy industries key to the UKCS’ future will be the cornerstones of an integrated energy system. In order for these hubs to be deployed
optimally, innovation is required across all four sectors, for example eliminating methane leaks, reducing the cost of floating wind foundations, optimising blue hydrogen production and better understanding CO2 reservoir behaviour. All infrastructure developed for and around such energy hubs will also need to consider end-of-life, with designs that allow for easy decommissioning or repurposing.
Storage and transportEnergy storage and transport will be crucial to safeguarding the UK’s energy supply. Developing the technology to reliably identify and deliver suitable geological options for long and medium term energy storage will be critical to
ensuring that system costs are minimised. Repurposing the existing offshore infrastructure, and constructing new purpose-built infrastructure, will require innovation in materials, equipment, installation methods and renovation techniques.
12
Contents
Sizing up the UKCS on the Road to Net Zero 2.1. Introduction to the UKCS . . . . . . . . . . . . . . . . 242.2. UKCS resource base. . . . . . . . . . . . . . . . . . . 312.3. Policy, regulation and commitments . . . . . . . . . 68
Introduction 1.1. Project Vision. . . . . . . . . . . . . . . . . . . . . . . 201.2. Introduction to Closing the Gap —
Technology for a Net Zero North Sea report . . . . . 21
3 456
Closing the Gap to 2050 Technologies 3.1. Introduction and approach
to the technology roadmap . . . . . . . . . . . . . . . 763.2. Oil and gas emission reduction technologies . . . 80 Platform electrification Flaring and venting mitigation Methane leak mitigation Subsea technologies Oil and gas ecosystem and path to 2050 Speculative technologies for oil and gas Oil and gas technology roadmap
3.3. Renewable energy technologies . . . . . . . . . 100 Fixed-bottom offshore wind Floating offshore wind Airborne wind Other renewables Transmission, connection to the grid and to the platform Geothermal energy Energy storage Renewable energy ecosystem and path to 2050 Speculative technologies for renewable energy Renewable energy technology roadmap
3.4. Hydrogen technologies . . . . . . . . . . . . . . 122 Hydrogen production Hydrogen storage and transport Hydrogen use on the UKCS Technology accelerators,
enablers and dependent technologies Hydrogen ecosystem and path to 2050 Speculative technologies for hydrogen Hydrogen technology roadmap
3.5. Carbon capture, utilisation and storage (CCUS) technologies. . . . . . . . . 149
Value chain overview CO2 capture CO2 transport CO2 storage CO2 utilisation Technology accelerators,
enablers and dependent technologies CCUS ecosystem and path to 2050 Speculative technologies for CCUS CCUS technology roadmap
3.6. Digitalisation of equipment and operations . . . 171 Ecosystem and Path to 2050 Implications for industry
Integrated Energy System Roadmap 4.1. Changing UKCS landscape . . . . . . . . . . . . . . .1794.2. Development of an integrated energy system . . . .1864.3. Meeting the CCC targets . . . . . . . . . . . . . . . .188
7
BenefitstotheUK:Economicimpact of achieving net zero targets
5.1. Introduction to input-output analysis . . . . . . . . .1955.2. Sector outlook . . . . . . . . . . . . . . . . . . . . . .196 Oil and gas Offshore renewables Hydrogen CCUS5.3. UK impact summary . . . . . . . . . . . . . . . . . .208
Unlocking the Potential 6.1. Technology gap priorities for unlocking
the UKCS’ potential . . . . . . . . . . . . . . . . . . .2186.2. Technology Challenges . . . . . . . . . . . . . . . . 220
7.1. Appendix . . . . . . . . . . . . . . . . . . . . . . . . 2227.2. References . . . . . . . . . . . . . . . . . . . . . . . .226
Introduction1
1.1: Project VisionThe Project Vision was created at the start of the work through a cross-sector workshop with more than 30 industry representatives. Its purpose is to provide context to what net zero UKCS means, highlighting the most important characteristics. This statement gave the project team a shared understanding of what a net zero UKCS means beyond the balance of emissions.
To develop the UKCS into a net zero integrated energy system that will sustain the offshore sector’s critical role in the nation’s economy, energy infrastructure and secure supply of affordable energy.
The UKCS will play a pivotal role in meeting the national net zero target delivering sustainable energy and leading the way on carbon sequestration.
This transition will harness the unique qualities of the UKCS. That is, world-class oil and gas and renewables sectors, with abundant natural resources, connected to substantial domestic and international markets. Integral to achieving the net zero target, will be the development of new businesses that supply skills, services and technologies to the UK and global energy markets. The energy industry will work collaboratively with other UKCS stakeholders to ensure the sustainable use of offshore resources while reaching the net zero target.
isolation to date, far more joined-up working will be needed to meet the UK’s net zero commitments. This will require integrated thinking.
To support the progression of an integrated energy vision for the UKCS – a vision dependent on technology development – the OGTC identified the need for a review and analysis of the technologies that will be required to realise a net zero future. This Closing the Gap — Technology for a Net Zero North Sea study addresses that need. It is a cross-sector analysis highlighting the technologies that will be instrumental in achieving a net zero UKCS. The focus is on technologies that can contribute the most to achieving this goal in the key offshore sectors – oil and gas, renewables, hydrogen and CCUS – and the innovation gaps that will need to be closed.
Part one of the study (Sizing up the UKCS on the road to net zero) establishes the current position in each sector. From there, we have developed a technology roadmap (Closing the Gap to 2050 Technologies) that prioritises and assesses each technology’s potential contribution and the extent of the innovation gaps that need to be closed. Using the CCC’s 2050 targets and the industry’s Roadmap 2035 as a guide, our report identifies and assesses the key technologies that can play a role in achieving the UK’s net zero targets and because our report takes a 30-year view across the energy system, there are a large number of options to consider.
The final part of the study evaluates the economic impact for each sector (Benefits to the UK: Economic Impact of the Roadmap) and how this will evolve over the next 30 years, highlighting the investment that will be required and the job creation potential of each technology. While the net zero target is the key driver of this analysis, the economic benefit of developing these low-carbon sectors, both in terms of domestic economic impact and export potential, is a primary consideration.
In May 2019 the Committee on Climate Change (CCC) recommended that the UK should legislate as soon as possible to reach net zero greenhouse gas emissions. As a result, the Climate Change Act 2008 was amended in June 2019, committing the UK to reducing carbon emissions by at least 100% of 1990 levels (net zero) by 2050 and to work to reduce global emissions. In doing so, the UK became the first major economy to pass a net zero emissions law. Soon after, in September 2019, the Scottish parliament passed the Climate Change Act which commits Scotland to achieving net zero emissions by 2045. In June 2020 the UK’s offshore oil and gas industry then committed to cutting operational emissions 50% by 2030, 90% by 2040 and to achieve net zero production by 2050.
These new targets require a radical change to the way we produce and consume energy and resources. Technology will enable this transition by reducing emissions from current operations and providing new sources of clean energy.
For decades the offshore oil and gas sector has been at the heart of the UK economy and while this will continue to be the case, the types of activities and their operations in the UK will need to be transformed. UKCS has long been synonymous with oil and gas, but in the coming years and decades, it will become just one part of a diverse mix of renewable energy, clean fuels and carbon storage.
The Oil and Gas Technology Centre (OGTC) leads research into technology development on the UKCS. In 2019, in partnership with industry, it created the Net Zero Solution Centre to accelerate the development and deployment of technologies to decarbonise offshore operations. In support of Roadmap 2035, it aims to develop the UKCS into the first net zero oil and gas basin globally. This initiative has been a springboard for cross-sector engagement between the oil and gas, renewables, hydrogen and CCUS sectors, among others. While these sectors have predominantly operated in
1.2: Introduction to Closing the Gap — Technology for a Net Zero North Sea report
Intr
oduc
tion
| Se
ctio
n 1
Intr
oduc
tion
| Se
ctio
n 1
2120
Sizing up the UKCS on the Road to Net Zero2
2.1: Introduction to the UKCS
History of UKCSThe UK Continental Shelf (UKCS) is the area of water that the UK has mineral rights to and includes parts of the North Sea, Irish Sea, Celtic Sea, English Channel and Atlantic Ocean. The UKCS has contributed substantially to the UK’s energy industry and economy since the early 1960s, primarily through oil and gas production.
The exploitation of the UKCS drove the development of the UK’s oil and gas industry and in the process made a vital contribution to the global offshore industry. Oil and gas exploration started on the UKCS in the early 1960s, with the first offshore well drilled in 1964 and first discovery made in 19651. Hydrocarbon production started in 1967 and peaked first in the mid 1980s, reaching 3.3 million barrels of oil equivalent per day (mmboed), and then again in the late 1990s when production reached 4.5 mmboed1. Since 1999, oil and gas production from the UKCS has been declining, reaching a low of 1.4 mmboed in 20131. A renewed focus on exploration and maximising economic recovery has reversed this decline with production increasing year-on-year since since 2014 to present. (see figure 2.1).
Establishing the UKCS oil and gas industry in the 1960s and 1970s required new standards for offshore operations: developments in a harsh marine environment and in such water depths had not been attempted before.
The West Sole field in the Southern Gas Basin produced the UKCS’ first gas in 1967, whilst the discovery of the Arbroath field in 1969 represented the first domestic oil production. Soon after, the Forties field was discovered, establishing the UKCS as a global player in the oil and gas industry. Developing fields in extreme offshore conditions fostered innovation, and created new technologies which have been exported the world over. The ‘North Sea Standard’ became a global operations benchmark and made the UKCS a centre of excellence. Looking to a net zero future, this rich heritage of engineering leadership and innovation provides a strong foundation for developing renewable technologies, carbon sequestration and an integrated offshore energy network.
0
500
1000
1500
2000
2500
3000
3500
4000
4500
5000
1965
1967
1969
1971
1973
1975
1977
1979
1981
1983
1985
1987
1989
1991
1993
1995
1997
1999
2001
2003
2005
2007
2009
2011
2013
2015
2017
2019
UKCS Onshore
UKCS Onshore
1%
99%
Source: Wood Mackenzie
Figure 2.1: UK oil and gas production (1965-2020)
Source: Wood Mackenzie
Figure 2.2: UK offshore vs onshore historic oil and gas production
UKCS OnshoreM
illio
n ba
rrel
s of
oil
equi
vale
nt p
er d
ay (m
mbo
ed)
0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
5.0
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
2524
UK offshore wind capacityRecently the UKCS’ potential for offshore wind generation has started to be realised. In 2003, operations began at the UK’s first commercial offshore wind farm: the 60MW North Hoyle farm located off the coast of Liverpool. By 2005, the UKCS’ wind capacity had reached 0.2GW and grew another 1GW over the next five years to 1.2GW (see figure 2.3).
From 2010 onwards, technological developments, newly enacted climate policy and subsidies accelerated offshore wind expansion. The UK held its first offshore wind capacity auction in 2014, and in 2015 the UK’s installed capacity reached 5.1 GW. In 2017, Equinor began operations at the world’s first commercial floating wind farm: the 30MW Hywind Scotland project, located 15 miles off Peterhead in Scotland. As of the end of 2019, the UK is still the only country in the world to host an operational floating wind farm and is currently the world leader in offshore wind, with more installed capacity than any other country.
Economic benefits of UKCSThe UKCS provides significant socio-economic benefit to the UK, contributing tax revenues and jobs, as well as helping to meet the country’s energy demand.
Oil and gas production from the UKCS contributes 1.2% to the UK’s GDP2, having previously reached a high of 2.5% of GDP in 20083.
Since 1970, the oil and gas industry has contributed over £350 billion in government tax revenue2. Oil and gas tax revenue peaked in 2008 when it reached more than £12.5 billion4, ~3% of total government tax revenue in that year5. Since then, tax revenue from oil and gas has been falling and during the oil price crash of 2014 to 2016 reached zero3. In the 2017 to 2018 fiscal year, UKCS oil and gas companies paid £1.2 billion in tax revenue6,7, less than 1% of total government taxes5. Offshore wind has been supported by the UK government through subsidies. However, as the costs of offshore wind development continue to decline, and market structures evolve, the subsidies paid out by the government for new projects is reducing8.
The UK oil and gas supply chain exports approximately £12 billion of goods and services each year2. Exports of wind energy products and services are currently estimated to be worth £525 million per year9.
In total, energy related activities on the UKCS accounted for approximately 1% of all UK jobs in 201811. The UK oil and gas industry employed 259,900 people — through direct (30,000), indirect (116,000) and induced (113,000) employment10. That number has fallen from a high of 463,900 in 201410 (1.5% of the total UK workforce). 7,200 people were directly employed in the offshore wind sector12, approximately 0.02% of the UK’s total workforce13,14,15, and an estimated 700 people worked in the marine energy (tidal and wave power) sector in 201816.
9GW5.1GW1.2GW0.2GW
2020
2005
2010
2015
2000: Installation of the UK’s first demonstration offshore wind farm
2017: Operations begin at UK’s first floating windfarm
This rich heritage of engineering leadership and innovation provides a strong foundation for developing renewable technologies, carbon sequestration and an integrated offshore energy network.
Figure 2.3
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
26 27
Energy benefit of UKCSResources from the UKCS provide for just under half of the UK’s energy, this is primarily from oil and gas which currently meets over 45% of the UK’s total energy demand2 (see figure 2.4).
Carbon emissions from UKCSIn 2018 the UK produced 451 million tonnes CO2 equivalent (MtCO2e )of greenhouse gas emissions. Oil and gas produced from the UKCS contributes significantly to these emissions19,20.
Direct emissions (scope 1) from oil and gas activity on the UKCS amounted to 14.6 MtCO2e, approximately 3% of total emissions. The generation of energy (mostly from fossil fuels) produced 23% of emissions, and the transport industry (mostly through the use of oil-based products) accounted for a further 28% (see figure 2.5)19. As UKCS production meets more than three quarters of the UK’s oil demand and half of the UK’s gas demand, scope 3 emissions associated with resources from the UKCS make up a large proportion of the UK’s total GHG emissions. Additionally, hydrocarbons that are imported to meet the remainder of gas and oil demand also contribute to embedded GHG emissions.
Source: UK government
Figure 2.5: UK GHG emissions (1997-2017)
UKCS energy generation
(2018)
2%Offshore wind
60% Oil
37% Gas
N.B Energy mix: sources of all energy usage, includes electricity generation, transport, residential, commercial and agriculture (RCA), industry and losses. Power mix: sources of electricity generation.
Source: Wood Mackenzie
52% other sources (including imported oil and gas)
48% UKCS sources
UK energy consumption
(2018)
18%Gas
1%Offshore wind
29%Oil
Source: Wood Mackenzie
Figure 2.4
Renewable energy sources (solar and wind, but excluding hydro) account for approximately 4% of the UK’s primary energy demand, with offshore wind meeting just over 1% of the country’s energy usage17,18. Wind and solar’s share of electricity is higher, currently generating a fifth of the UK’s supply; again, offshore wind accounts for just under half of this power generation (8% of the UK’s total electricity generated in 2018).
Box 2.1: Greenhouse gas emissions categories
Scope 1
All Direct Emissions from the activities of
an organisation or under their control
Scope 3
All Other Indirect Emissions from activities of the
organisation, occurring from sources that they do not own or control, i.e. end
use of products
Scope 2Indirect Emissions
from electricity purchased and used by the organisation
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
2928
UKCS stakeholder groupsOutside of the energy industry there are a number of other stakeholders who have significant economic, logistic and ecological interests on the UKCS. These include commercial shippers, the fishing and aquaculture industries, oceanographic and hydrography researchers, the Royal Navy, and communication companies21.
Historically the energy industry and other stakeholders have worked together on the UKCS. For example, the Fisheries Legacy Trust Company (FLTC) manages interactions between the offshore oil and gas industry and fishing industries, and all offshore oil and gas operators must have a Fisheries Liaison Officer to collaborate with the government and fishing organisations on relevant issues22.
Group Stakeholders DescriptionNECCUS (North East CCUS)
Industry (i.e. Shell, Total, Chrysaor, Pale Blue Dot, Ineos), academia (i.e. University of Aberdeen, University of Edinburgh, University of Strathclyde, Heriot Watt University), NGOs (i.e. Scottish Government and Crown Estates Scotland) and other orgnaistaions (i.e. OGTC, SHFCA, Opportunity North East)
Industry-led alliance drawn from industry, academia, membership organisations and private sector bodies to promote CCUS in Scotland
Hydrogen Taskforce BP, Shell, BNP Paribas, Arup, ITM Power, Arval, Cadent, Storengy, DBD and Baxi
Political alliance that promotes hydrogen as an alternative fuel and provides government with suggested hydrogen related aims
Industrial Decarbonisation Research and Innovation Centre (IDRIC)
Industrial Strategy, Engineering and Physical Sciences Research Council
Aims to accelerate the cost-effective decarbonisation of industry by developing and deploying low- carbon technologies
CCUS Cost Challenge Taskforce
Industry (i.e. Shell, BP, Equinor, Cadent Gas, BHP, Summit Power, Siemens, Pale Blue Dot etc.), academia (Cambridge university, Imperial College London etc.), NGOs (Crown Estate, Crown Estate Scotland) and international organisations
Aims to inform and propose a strategic plan for supporting the development of CCUS in the UK
2.2: UKCS Resource BaseThe UKCS has a large, unique resource base ranging from natural processes, such as wind and wave, to natural materials, such as gas and oil.
As the exploitation of these resources progresses, policies develop and demand changes, new uses for the UKCS are being considered. For example, the huge volumes of depleted hydrocarbon reservoirs that initially provided oil and gas are now being considered as storage sites for captured CO2.
Further to this, natural gas that has been historically used in its original form is now being considered as a source for hydrogen production. Other natural processes are also being investigated for their renewable power generation potential. Although the UKCS’ potential is currently exploited through standalone activities (see figure 2.6 which represents the current configuration of UKCS operations), the development of a connected energy system which unlocks the different resources’ potential will be key to realising the UKCS’ net zero future.
Table 2.1: Some of the UKCS low-carbon groups
As the energy mix of the UKCS develops and offshore infrastructure evolves, continued close cooperation between stakeholders will be important to ensure all interests are considered.
Additionally, established UKCS stakeholders will need to diversify from traditional activities and work together to tackle the climate change policies relevant to reaching net zero. For example, the Oil and Gas Climate Initiative (OGCI) is planning to spend more than £750 million on implementing and scaling low carbon solutions in oil and gas, industrial and commercial transportation23. BP and Shell are also part of a new hydrogen taskforce which aims to plan how the UK can effectively capitalise on hydrogen opportunities24.Several other UKCS stakeholders have grouped together to form cross-sector alliances and academic research groups to investigate how the different industries can work together to develop the utilisation of the UKCS. These groups are summarised in the table below:
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
30 31
UKCS current reality 2020
Figure 2.6
Source: Wood Mackenzie, Lux Research
Industrial Cluster
Petrochemical cluster
Power plant
Domestic supply
FPSO
OIL/GAS PIPELINEPOWER CABLE
Subsea development
Concept shown is illustrative
Schematic view of the current set-up of UKCS energy system with stand-alone oil and gas and offshore wind
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
3332
Scale of resourceThe UKCS contains several prolific petroleum basins which can be broadly divided into five main areas: Central North Sea, Northern North Sea, Southern Gas Basin, West of Shetland and Atlantic Margin.
Over the past 50 years the Southern Gas Basin has been a prolific gas producer and the Central and Northern North Sea basins have been key to producing both oil and gas.
More than 45,000 million barrels of oil equivalent (mmboe) of oil and gas has been produced to date and Wood Mackenzie estimates there is 6,800 mmboe of reserves remaining (under current cost and pricing assumptions)1. Total production from the UKCS was 1.7 mmboed in 20186, with liquids production averaging just over 1 mmboed and gas production around 3,600 million cubic feet per day1. The West of Shetland is the UKCS’ key growth region and has a total remaining reserves base of 2,000 mmboe of oil and gas (see figure 2.7), with large development projects at Clair, Rosebank and Cambo accounting for 1,400 mmboe of these reserves1.
More than 45 billion boe of oil and gas has been produced to date and Wood Mackenzie estimates there is 6.8 billion boe1 of reserves remaining
OIL & GAS
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
3534
Southern Gas Basin
Central North Sea
Northern North Sea
West of Shetland
Atlantic Margin
Southern Gas Basin
Central North Sea
Northern North Sea
West of Shetland
Atlantic Margin
Remaining commercial resource
Lead and prospect prospective resource
500 million boe remaining oil reserves
500 million boe remaining gas reserves
1 billion boe resource
Figure 2.7: UKCS remaining reserves by basin and hydrocarbon type
Source: Wood Mackenzie Source: Wood Mackenzie, OGAPlay level prospective resource
Figure 2.8: UKCS remaining reserves and prospective resource
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
36 37
RegulationAn independent review of the UKCS oil and gas industry was published in 2014 and informed the UK government Energy Act 2016, which created the Oil and Gas Authority (OGA). The OGA was charged with effective stewardship and regulation of the UKCS, which includes responsibility for licensing.
The OGA holds regular licensing rounds covering areas in both the mature UKCS basins and exploration opportunities in frontier basins.
In May 2020 the OGA published a consultation on an update of its core aims to include a requirement for the oil and gas industry to help achieve the UK net zero target by 2050403.
Current issues facing sectorBalancing efforts to sustain oil and gas production with growing pressure to reduce carbon emissions has become a key focus for the industry. Additionally, decarbonising hydrocarbon products to support a net zero economy and sustainable fuel demand is becoming increasingly important.
Direct emissions from offshore oil and gas activities account for approximately 3% of the UK GHG emissions and three quarters of these offshore emissions are due to power generation on platforms. The remaining emissions are a result of fugitives, flaring and leakages.
In 2019, OGUK – the industry body for the UK offshore oil and gas industry - publised its “Roadmap 2035; a Path to Net Zero” report which outlines how the industry will balance energy security, economic and emissions objectives over the next 15 years. The Roadmap sets specific targets for the industry to reach2:
• Become a net zero GHG emissions basin by 2050
• Meet at least 50% of UK oil and gas demand from domestic production — thereby minimising higher carbon intensity imports
• Grow and diversify energy supply chain export revenues to £20 billion per year (from the £12 billion currently)
• Secure at least 130,000 direct and indirect jobs
• Create over £10 billion in economic value through technology and innovation
The UKCS is a mature hydrocarbon region. In an attempt to offset production decline, a ‘Maximising Economic Recovery’ (MER) strategy was recommended as part of a 2014 industry review1. The OGA subsequently implemented changes in the licensing regime to encourage new exploration, administered two government-funded seismic campaigns and continues to thoroughly review requests to cease production at older fields. More recently, the OGA has been developing initiatives to reduce the carbon footprint of offshore operations and to support carbon capture and storage and hydrogen, thus contributing to the UK’s net zero target403. The OGA’s UKCS Energy Integration407 report, published in August 2020, in collaboration with Ofgem, The Crown Estate and the Department for Business, Energy and Industrial Strategy (BEIS), highlights how the integration of offshore energy systems, including oil and gas, renewables, hydrogen and carbon capture and storage, could contribute to deliver approximately 30% of the UK’s total carbon reduction requirements needed to meet the 2050 net zero target.
A more immediate issue for the oil and gas sector to address is the decommissioning of ceased fields, removal of infrastructure and abandonment of wells. Over the next 15 years this is estimated to cost around £50 billion (2019 terms)1.
...the Majors still hold 20% of the total licensed acreage and more than 40% of remaining reserves.
Figure 2.9: Top oil and gas producers in the UK (net entitlement production - 2020)
Source: Wood Mackenzie
Corporate landscapeMajor oil companies, including BP and Shell, have historically dominated oil and gas activity on the UKCS. As the industry has matured, the corporate landscape has become increasingly fragmented, with more than 100 companies now holding acreage on the UKCS.
Collectively, the Majors still hold 20% of the total licensed acreage and more than 40% of remaining reserves1. However, for the first time since UK production began, a non-Major oil company is now the top producer. Chrysaor’s acquisition of ConocoPhillips’ UK business, coupled with asset divestments by Total, puts the private equity-backed player at the top of the production charts for 2019 (see figure 2.9).
Shell is set to be the largest investor on the UKCS in 2020 as a result of ongoing development at the Penguins field and infill drilling at Clair Ridge and Schiehallion. In 2019, Total and BP were the two largest investors in the UK, driven by development activity in the central North Sea in the case of the former, and exploration West of Shetland in the case of the latter. Chrysaor, Equinor and Apache are also major investors, focusing on development activity in the North Sea1.
EnQuest
ExxonMobil
Premier Oil
Delek Group
Apache
Centrica
Shell
BP
Total
Chrysaor
0.0 0.02
Operator Partner
0.04 0.06 0.08 0.10 0.12 0.14 0.16 0.18 0.20 0.22(mmboe)
0.21
0.18
0.15
0.13
0.08
0.07
0.07
0.06
0.06
0.05
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
38 39
<10 years
10-20 years
20-30 years
30-40 years
40-50 years
50+ years
<10 years
10-20 years
20-30 years
30-40 years
40-50 years
50+ years
<10 years
10-20 years
20-30 years
30-40 years
40-50 years
50+ years
14%
7%
30%
13%
21%
15%
302installed platforms
<10 years
10-20 years
20-30 years
30-40 years
40-50 years
50+ years
<10 years
10-20 years
20-30 years
30-40 years
40-50 years
50+ years
<10 years
10-20 years
20-30 years
30-40 years
40-50 years
50+ years
Installed pipeline age
13%
3%
37%25%
14%9%
12,000km+installed pipeline
Existing infrastructure
Figure 2.10 - UK offshore oil and gas infrastructure
After more than 50 years of oil and gas production, the UKCS has a substantial amount of infrastructure in place: more than 300 platforms25 and 12,000 km of pipelines26. However, much of the infrastructure is ageing; more than 40% of existing platforms25 and a quarter of existing pipelines26 were installed more than 30 years ago.
Source: Wood Mackenzie
Source: Wood Mackenzie
Figure 2.11: Installed platform age
Source: Wood Mackenzie
Platform
Gas
Facility
Pipeline
Terminal
Oil
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
40 41
Figure 2.12: Field platform age at UK fields
As fields reach the end of their lives and are decommissioned, operators need to plan for removal of platforms and associated infrastructure (subsea structures and pipelines). This decommissioning activity is ongoing across the UKCS with a particular focus on the most mature areas like the Southern Gas Basin. It is planned that over a third of existing platforms will cease operating within the next five years, and a further third will cease operating before 203025.
How many oil and gas platforms can be repurposed for other uses is unclear, as in most cases they are old and integrity issues mean maintenance costs are high. Additionally, the repurposing of oil and gas wells for long-term CO2 injection is still uncertain as they were designed and located for different objectives.27.
Current uncertainty about the future of the concrete gravity-based structures and whether they will be left in place or removed makes them potential hubs for alternative projects such as carbon storage, substations for electrical networks or for locating electrolysers. The extensive oil and gas pipeline infrastructure across the UKCS could be used for a CO2 or hydrogen network, although once again, integrity issues will be a serious consideration due to the age of the networks.
The extensive oil and gas pipeline infrastructure across the UKCS could be used for a CO2 or hydrogen network, although integrity issues will be a serious consideration due to the age of the infrastructure.
Source: Wood Mackenzie
>50
31-40
Field Platform Age
Facility
41-50
21-3010-20<10
Gas
Pipeline
Terminal
Oil
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
42 43
UK — a world leader in offshore windThe strong wind speeds, shallow water depths and appropriate seabed substrate (see figure 2.13), alongside early adoption, technology evolution and clear political will, have resulted in the UK becoming the world leader in offshore wind, with more installed capacity than any other country28.
The deeper water depths of parts of the North Sea are ideal for floating wind, where bottom fixed wind turbines are not viable. Estimates show that over half of the North Sea is suitable for deploying floating wind power29.
WIND
At the end of 2019 the UKCS had an installed capacity of 8.6GW30 across more than 35 operational offshore wind projects. In 2020, offshore wind is expected to generate 10% of the UK's electricity28.
In total 20 projects are currently planned or under construction on the UKCS and will contribute an additional 19GW of capacity over the next 10 years30,31. A further 16GW of capacity is in the planning stage but is yet to receive a permit30. The Government aims to reach 40GW of offshore wind capacity by 203032 and looks on target to do so with the 34GW of capacity in the active pipeline (see figure 2.14)30.
The key drivers of growing offshore wind capacity are continued cost reduction and government policy which is aiming to increase renewables’ share of the UK’s energy mix30.
In the longer term, the potential for operators to sell electricity at higher prices directly to the market - rather than agreeing strike prices with the government - and technological developments such as increasing project size, will be the primary drivers of capacity growth.
Figure 2.13: UKCS physical conditions relevant for offshore wind developments
Wind speed Substrate type Sea depth
4544
Figure 2.14: Offshore wind capacity by location
Source: Wood Mackenzie
Note: *’Operational’ refers to capacity which is fully grid-connected (including decommissioned capacity).**’Secured pipeline’ refers to capacity which has been awarded a support scheme but is still not operational. ***’Early stage’ refers to capacity which has not secured a support scheme.
Figure 2.15: Upcoming UK offshore wind leasing rounds
20%
43GWtotal pipeline capacity
26%
54%
Operational* Secured pipeline** Early stage pipeline***
1GW Project SizeDPO – no ornithological constraints
DPO subject to the need for further regional level survey and assessment
Likely that no license or consent can be awarded without further evidence
DPO subject to high levels of ornithological constraint
Likely that no license or consent can be awarded
Dogger Bank Eastern • Southern North Sea region • The Wash region • East Anglia region South East
Northern Wales & Irish Sea • North Wales region • Irish Sea region • North part of the
Anglesey region
Source: Wood Mackenzie, Scottish Government, The Crown Estate Information Memorandum - Introducing Offshore Wind Leasing Round 4
Draft Plan Options (DPO) for ScotWind | 10 GW+ offshore capacity expected to be awarded
Crown Estate leasing round 4 bidding areas | 7 GW - 8.5 GW new seabed rights
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
46 47
RegulationThe Crown Estate holds all rights to the seabed around England, Wales and Northern Ireland and is responsible for awarding developers the rights to install offshore technology33. The Crown Estate Scotland is responsible for awarding and managing leases in the Scottish section of the UKCS34.
The Offshore Wind Leasing Round 4 was launched at the end of 2019 and offers more than 7GW of seabed rights in waters around England and Wales (see figure 2.14)30,35. Seabed in Scotland is being leased through the 2020 ScotWind leasing round which was launched in June 2020 and offers up to 10GW of capacity across a variety of locations in Scotland (see figure 2.15)36. A portion of this capacity is floating wind.
Since 2014, the UK government, on behalf of the Crown Estate, has also held three Contracts for Difference (CfD) Allocation Rounds (AR) as a means to support new offshore wind capacity. During these rounds, more than 9.8 GW of capacity support has been awarded8.
In 2019, the UK government and offshore wind sector released the Offshore Wind Sector Deal which outlines how the Government and sector will work together to continue to support offshore wind growth. The deal outlines that the sector should aim to increase UK content to 60% by 2030, the number of UK jobs in offshore wind to 27,000 and exports from £0.5 billion currently to £2.6 billion by 203012. To achieve that, the sector will invest up to £250 million to develop the UK supply chain and establish the Offshore Wind Growth Partnership (OWGP) to support productivity and increase competitiveness12.
Corporate landscapeThe UK market has attracted large foreign suppliers and 32% of the major suppliers are now based in the UK. However, 68% of the offshore wind supply chain is sourced from non-UK based firms 37.
SSE is one of the most active onshore and offshore wind developers and operators in the UK and is one of the few developers based in the UK14.
As of the end of 2019, the Danish company Ørsted had the largest UK offshore wind portfolio (see figure 2.16)14. Other companies with large UK offshore wind portfolios include RWE, Vattenfall, Iberdrola and Equinor38. In the latest Contract for Difference (CfD) Auction Round 3 (AR3) support auctions, SSE took 41% of awarded capacity, Equinor 33% and Innogy 26%8. Other major energy players are showing an interest in the UK’s offshore wind sector, such as Total who in March 2020 acquired a stake in a UK floating project.
Source: Wood Mackenzie
Figure 2.16: Top offshore wind developers in UK by portfolio status - 2019
The Offshore Wind Sector Deal builds on the United Kingdom’s global leadership in offshore wind, maximising the advantages for UK industry from the global shift to clean growth.
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
48 49
Current issues facing sectorKey barriers to offshore wind growth are uncertainty around power prices, competition from alternative fuels and worsening area characteristics as all the ‘best’ wind areas are licensed30 and projects are forced to locate in more technically challenging areas further from shore39.
Cost reductions
The UK’s offshore wind levelised cost of energy (LCOE) has nearly halved since 2012 and is expected to drop by a further 64% by 2028, from ~£100/MWh in 2019 to just under ~£40/MWh (see figure 2.17)39.
As projects are pushed to locate in less attractive and more complex areas (they are already being deployed over 100km from the shore and in water depths of more than 50 metres12) they will have higher capital costs (capex). However, the average offshore wind LCOE in the UK will continue to decline, as technology improves, more innovative ways of working become standard, projects benefit from economies of scale and synergies and demand outlook steadies.
Source: Wood Mackenzie
In the UK’s latest wind capacity support auction, AR3, the awarded strike prices ranged between £44.95/MWh and £47.18/MWh (indexed to 2019 prices). This was 35% lower than that in AR2 and close to the average wholesale electricity price of around £45/MWh in 20198. The low strike prices indicate that the cost of offshore wind is comparable to other traditional power generation options and a competitive electricity option.
New technology
The UKCS' higher mean wind speeds and less extreme weather conditions compared to many developing wind markets mean that it can offer attractive opportunities for the adoption of the latest offshore wind turbine technologies.
The Hornsea Project One is planned to start operations this year and will overtake the 659MW Walney Extension in the Irish Sea, as the largest offshore wind farm in the world40. The farm is located off the coast of Hull and will have a total capacity of 1.2GW from 174 turbines, each 190 metres tall and spread across an area 407km2 in size41. Both Walney Extension and Hornsea Project One are operated by Ørsted.
Transmitting power to the UK market is becoming increasingly complex as wind farms are located further offshore. The Dogger Bank project, in the Southern Gas basin, will utilise high voltage direct current (HVDC), which is expected to mitigate energy transmission losses and could also lower transmission asset construction costs39.
As the bulk of easy to access, shallow water wind locations are already licensed, the industry is starting to investigate floating offshore wind’s potential. The world’s first floating offshore wind farm was installed 15 miles off Peterhead in Aberdeenshire by Equinor in 2017. The 30MW Hywind Scotland project is currently the only existing project of its kind29, yet more than 75 floating wind concepts are being considered worldwide and more than 350MW of floating wind demonstrators are set to be grid connected in the next five years. Of these, 22% are in the UK41.
Floating wind has advantages over fixed-bottom wind: it is less intrusive for the seabed, the location can be more flexible and there is greater potential for standardisation and mass production. However, policy-makers need to develop a clear route to market for the floating wind industry to take off at commercial scale. So far, the commercialisation of floating wind has been hampered by misalignment between developers and governments. Developers argue that capacity is needed to reduce the cost of floating wind, and governments counter that cost declines are needed to allocate generation capacity to floating wind.
Figure 2.17: UK offshore wind levelised cost of electricity (LCOE)
The world’s first floating offshore windfarm was installed 15 miles off Scotland’s northeast coast in 2017. 150
0
25
50
75
100
125
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
UK’s LCOE average Average power price - historical and WM forecast
£/M
Wh,
real
201
9
-64%
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
50 51
Existing infrastructure
Figure 2.18: Existing and planned UK offshore windfarms and electricity interconnectors
As the bulk of easy to access, shallow water wind locations are already licensed, the industry is starting to investigate floating offshore wind’s potential.
Source: Wood Mackenzie
Operational
Existing
Operational; Under Construction
Consented; Planned
Wind Farm - Status
Inter Connector
Wind Sites
Under Construction
Planned; Proposed
Planned
North Sea Link
East-West
Greenlink
Viking Link
Neu Connect
BritNed
GridLinkIFA, ElecLink
AQUINDIFA 2FAB Link
Nemo
North Connect
FacilityTerminal
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
52 53
Other renewables
Floating photovoltaics (PV) solar (high wave offshore solar)
The UK has an installed PV solar capacity of more than 12,000MW direct current (MWdc)42 – 0.1% of which (11MWdc) is floating PV solar43. Growth is expected to be slow as the economic case is not as clear as it is for wind43.
Offshore PV solar is expected to grow especially slowly due to the technical challenges associated with these projects and limited government support. To date, almost all floating PV solar projects have been deployed on lakes, reservoirs, fish farms, and other places where there are calm water conditions.
If floating PV solar were to be installed offshore, salt would erode components and rougher water conditions would create extra wear and tear. Both of those factors would add to project complexity and increase capital costs44. Nevertheless, there are several global projects going ahead with high-wave offshore solar plans.
The company Oceans of Energy claims to have developed the first offshore floating solar farm in the Dutch sector of the North Sea that has the ability to withstand waves up to 13 metres high and a capacity that will be expanded to 50 kW this year45. A Belgian consortium (led by Environmental and Marine Engineering (DEME), and including Dredging, Tractebel, Jan De Nul Group, Soltech and Ghent University) recently announced plans to invest £1.75 million in a “high-wave” offshore PV farm in the Belgian section of the North Sea46. These developments, if proven successful, could translate to further growth in floating PV solar on the UKCS.
Marine energy
Marine energy is electricity generated from the movement of water in oceans, rivers and seas. In 2018 the UK produced 8GWh of electricity from marine energy, less than 0.003% of the total electricity generated in that year47; however, it is estimated that the UK has a technical marine energy resource of 16,000 GWh per year48.
Marine energy can be split into two main technology sectors: wave and tidal. Tidal energy uses the power of tides to generate electricity and is usually found in estuaries or streams, whereas wave energy utilises waves to generate electricity. It is estimated that the UK has between 25 and 30 GW of tidal energy resource, primarily within estuaries, such as the Severn Estuary, or in the north west of the UK48. UK wave energy is estimated to have a potential resource capacity of up to 20GW48.
Tidal energy technology has now been operated under test and at-sea conditions and can be employed with a good degree of confidence49. Wave technology is still at a development stage and several different concepts are being progressed; however, there is still no agreement on its optimal design49. A total of 23 wave energy technology developers and 22 tidal device developers were active in the UK in 201849. As of 2018, installed tidal capacity in the UK was 10MW and capacity from wave projects - either operational or under development - was 137MW49. The levelised cost of energy (LCOE) for tidal and wave projects is estimated to be around £300/MWh based on recent projects/prototypes49.
The main barrier to marine energy development is a lack of route to market within existing government frameworks and no allocation of generation capacity. To achieve a route to market marine energy would have to prove it meets the government’s “triple test”: cost reduction, UK economic benefit and carbon reduction. Currently the technology is proving too costly; however, a study by ORE Catapult estimates that the LCOE associated with tidal power could reduce to £80/MWh as the scale of installed capacity increases49.
The main barrier to marine energy develop-ment is a lack of ‘route to market’.
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
54 55
Hydrogen
The main uses of hydrogen in the UK today are in fertiliser production and oil refining to produce low sulphur petrol51. However, hydrogen can be used as an alternative to natural gas in the heating, industry, transport, chemicals and power sectors; traditionally very high emission intensive industries52.
There is a strong case for hydrogen as an alternative to natural gas in the energy system as it is:• Abundant (hydrogen is the most abundant element on earth) • Clean (hydrogen produces no emissions at the point of use)• Produces an abundance of energy (hydrogen has one of the highest
energy densities by mass of any fuel)• Can be stored and transported efficiently (hydrogen can be stored and
transported in a variety of forms)
There are four processes for producing hydrogen, all with differing deployment levels and variable associated GHG emissions (see Box 2.1). Currently, over 95% of hydrogen is produced from fossil fuels53, which accounts for the use of 6% of global natural gas and 2% of global coal . These processes result in the production of approximately 2% of total global emissions (as of 2017)54. Green and blue hydrogen are produced by lower emission processes. The development of technology associated with green and blue hydrogen production is therefore required to make hydrogen an effective low-carbon alternative in both existing operations and new uses. The abundance of natural gas production and growing renewable electricity production on the UKCS make it a key area for the development of both blue and green hydrogen production.
Box 2.2: Hydrogen formation processes
Over 50 million tonnes (Mt) of hydrogen is produced globally per year56. Only 0.74Mt of this is produced in the UK, mostly at the Esso Fawley refinery near Southampton,5 but there are more than 10 small scale hydrogen projects across the UK. The majority of the 27 Terawatt-hour (TWh) of hydrogen energy currently produced in the UK is for non-energy uses and is produced using Steam Methane Reforming (SMR), i.e. grey hydrogen52. A very small portion of UK hydrogen is produced via electrolysis and is primarily used in the transport sector58.
Hydrogen has been identified as key in helping the UK reach its emission reduction targets and several new low-carbon hydrogen projects have received funding both from the government and private companies. In February 2020, five projects received funding from the Department for Business, Energy & Industrial Strategy as part of the Hydrogen Supply Competition Phase 2;
• Dolphyn - £3.12 million - led by Environmental Resources Management Limited (ERM) - aims to develop a prototype floating wind turbine that also has systems for water intake, desalination and the conversion of water into hydrogen via proton exchange membrane technology59 (green hydrogen)
• HyNet - £7.48 million – led by Progressive Energy Ltd – aims to develop a clean hydrogen production facility with carbon capture and storage, as part of the HyNet Cluster (blue hydrogen)
• Gigastack - £7. 5 million - led by ITM Power Trading Ltd – aims to produce zero-carbon hydrogen through a gigawatt scale polymer electrolyte membrane (PEM) that uses electricity from the Hornsea Two offshore wind farm60 (green hydrogen)
• Acorn Hydrogen Project - £2.7 million – led by Pale Blue Dot Energy – aims to develop an advanced reformation process using North Sea Gas while capturing and sequestering the associated CO2 emissions (blue hydrogen)
• HyPER - £7.44 million – led by Cranfield University – aims to develop low carbon bulk hydrogen supply through pilot scale demonstration of the sorption enhanced steam reforming process (blue hydrogen)
Grey hydrogen
• Produced via thermochemical conversion of natural gas• Main processes are steam methane reformation (SMR),
partial oxidation (POX) or autothermal reforming (ATR)• Natural gas is the source of ~71% of global
hydrogen production54
• Process is associated with high emissions
Brown hydrogen
• Produced from the gasification of coal and lignite • Is widely used, especially in China and Australia, but is
less common method of production than SMR55
• Coal is the source of ~27% of global hydrogen production54
• Process is associated with high emissions
Blue hydrogen
• Produced via SMR, ATR or POX paired with carbon capture, utilisation and storage (CCUS)
• Process is associated with low emissions • As of the start of 2020 there were two operational blue
hydrogen plants; Air Products SMR in Port Arthur, Texas and Quest in Alberta, Canada
Green hydrogen
• Produced from water electrolysis powered by renewable electricity
• Accounts for 1% of hydrogen production54 • Currently very expensive to produce • Process is associated with low emissions
Hydrogen has been identified as key in helping the UK reach its emission reduction targets
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
56 57
Development of a hydrogen network and low-carbon industrial clusters will be imperative to the large scale hydrogen deployment needed to achieve the net zero targets. In 2019, Drax group, National Grid Ventures and Equinor announced plans to explore the feasibility of constructing a blue hydrogen production facility with carbon capture and storage in Humberside – the UK’s highest emissions industrial cluster (see figure 2.22) - with the aim of starting development of a zero carbon cluster by the middle of the decade61.
The Zero Carbon Humber project aims to capture CO2 from the new hydrogen facility, existing power station and other industrial activities in the Humber area before being transported via pipelines and stored in subsurface reservoirs or aquifers in the Southern North Sea61.
The project involves a range of energy companies that each have a unique role to play: Drax through continuing development of alternative fueled power generation, National Grid through the development of a regional CO2 pipeline network, and Equinor through utilising its UKCS subsurface knowledge to effectively store captured CO2.
Figure 2.21 provides details of other hydrogen projects including: Hydrogen Offshore Production (HOP) on Orkney; Project Acorn at St Fergus; HyNet Northwest on Merseyside; and H2H Saltend on Humberside.
Carbon capture, utilisation and storage Carbon capture, utilisation and storage involves capturing CO2 (either directly from emitting sources or from the atmosphere) and permanently storing it, usually in underground sites such as saline aquifers or depleted oil and gas reservoirs, or using it in another process.
CCUS can be used to reduce emissions at a variety of industrial facilities, including power generation, natural gas processing, petroleum refining, cement production, hydrogen reforming and chemical production62. Depending on the application, CCUS can reduce carbon emissions from industrial processes by 90%62. The huge volume of both aquifers and depleted oil and gas reservoirs on the UKCS make it a prime candidate for storing CO2.
Globally, there are more than 60 operational CCS projects of varying capture capacity (see figure 2.19). Of these, the Drax bioenergy plant is currently the only operational carbon capture project in the UK62 . The largest carbon capture trial in the UK took place at the Ferrybridge Power Station in West Yorkshire between 2011 and 2013 where 100 tonnes of CO2 was captured per day. Since 2009, 12 other CCS projects associated with coal power plants in the UK have been put on hold or cancelled62.
Five of the 32 global CCS project currently under development or construction are in the UK (see figure 2.21)62. Three of these projects are investigating the potential to capture CO2 at natural gas power plants and the other two projects are investigating capturing CO2 from gas processing and/or hydrogen production projects62.
Global installed CCS capacity was estimated at 41.9 million metric tons per year (MtCO2/yr) in 2019 (equal to 1.1% of global emissions in 201962); the UK has a current capacity of less than 0.5 MtCO2/yr 62. Based on currently announced projects, global CCS capacity will reach 85.3 MtCO2/yr by 2030. More than four times this capacity (461 MtCO2/yr) is required by 2030 to keep pace with a 2-degree warming trajectory62.
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
58 59
The UK government has established the CCUS Infrastructure Fund which dedicates £800 million to the development of CCUS projects in at least two sites, one to be operational by the mid 2020s and one by 203063. The sites earmarked for the CCUS projects include industrial clusters such as St Fergus in Scotland and Teesside, Humberside and Merseyside in England (see figure 2.22).
The economics of CCUS projects are still borderline due to high capital costs and long lead times64 which have resulted in many planned projects being put on hold or terminated. This has been the case for post-combustion CCUS schemes at coal-fired power plants, as well as cement and steel manufacturing. With regards to the latter, the applications have so far been only proven in theory. Significant policy incentives such as carbon taxes and the development of CCUS clusters are likely needed to help CCUS be competitive. On a cost of CO2 avoided (the carbon price needed to make a project economic) most applications of CCUS need a minimum carbon price of £75/tonne, approximately three times that of the current European traded carbon price (as of the start of 2020)65.
Utilising existing infrastructure and knowledge on the UKCS could be key in reducing CCUS costs66. The large number of depleted reservoirs on the UKCS make ideal candidates for storing CO2 as they have the required porosity for storage, thorough subsurface information and, in most cases, infrastructure already in place that could be used for CO2 transport and storage activities. However, there are uncertainties around the long term integrity of depleted reservoirs and monitoring for leakage could add significant complication and cost to projects. According to the Global CCS Institute, there is an estimated 78,000 MtCO2 storage potential in the UK, 8,000 MtCO2 of which is in depleted oil and gas fields.27
A study conducted by The Energy Technologies Institute in 2016 identified over 20 oil and gas fields suitable for CO2 storage and high-graded five for in-depth analysis27. These fields were selected based on substantial subsurface data already available, meaning there is high confidence that CO2 could be stored at commercial rates. A potential development plan was produced for each of these sites demonstrating how delivering between 3 and 10 MtCO2/yr storage capacity over a minimum 15-year period could be implemented cost effectively.
Although all the sites have existing infrastructure (platforms, wells and pipelines), the study recommended new infrastructure be installed as existing infrastructure was designed and installed for alternative purposes and so is not fit for purpose for CCS27.
Figure 2.19: Global operational CCS plants (by number)
Figure 2.20: UK capture and storage potential
28%
United States of America
China
10%
10%
Canada
Japan
Australia
Brazil
Netherlands
Spain
Norway
United Kingdom
All Others
8%
7%5%
5%
5%
3%
2%
18%
CO2
78,000MtCO2
UK CO2 storage potential
CO2
8,000MtCO2
CO2 storage potential in depleted reservoirs
Potential
ExistingCO2
365MtCO2
UK 2018 emissions
CO2
<0.5MtCO2
Current UK capture capacity
Source: Wood Mackenzie
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
60 61
Figure 2.21: UK CCUS and low carbon hydrogen projects
Figure 2.22: UKCS storage potential and highly emissive industrial clusters
A 2018 UK government funded study recommended the development of CCUS ‘cluster’ areas where CCUS could be developed in proximity to highly emissive activities such as gas fired power generation or blue hydrogen production. The five areas identified were; Teesside, Humberside, Merseyside, St Fergus Scotland and South Wales, all of which have existing industrial activity or potential for hydrogen developments (see figure 2.22). Blue hydrogen projects make up over 20% of the CCUS development pipeline due to the push for hydrogen through national hydrogen roadmaps and emissions reduction targets, and include projects in Humberside and Merseyside62.
No Project Name Stakeholders Aim Progress Type
1 Hydrogen Offshore Production (HOP)
Aquatera, Doosan, Cranfield University, EMEC Hydrogen, NOV, OGTC
Repurpose offshore infrastructure for hydrogen production and establish a test centre for hydrogen technology acceleration
Funding awarded by BEIS, feasibility study completed
2 Project Acorn — CCS and Hydrogen
Pale Blue Dot, Shell, Total, Chrysaor, Macquarie Group
Utilise existing infrastructure for transportation and then storage of CO2 in reservoir quality rocks (i.e. the Captain Sandstone) in the North Sea. The project then aims to reform North Sea gas to make hydrogen and store associated emissions using the Acorn CSS project
Funding awarded by BEIS, FEED study in progress, aiming for FID in 2021
3 The Caledonia Clean Energy Project
Summit Power Capture CO2 from natural gas-fired plant and store in depleted oil and gas fields in North Sea
Feasibility study completed
4 Net Zero Teesside
BP, Eni, Equinor, Shell and Total
Decarbonise a cluster of carbon-intensive businesses through CCUS
Feasibility study in progress
5 HyNet Northwest
Jaguar, Land Rover, Essar, Unilever, Inovyn, Encirc, Cargill, CPW, Novelis, Prinovis, Pilkinton, CF, Ibstock Brick, Essar, Solvay, North west Hydrogen Alliance
Develop blue hydrogen production and industrial fuel switching alongside CCS
Funding awarded by BEIS, FEED study in progress
6 Drax power station
Drax group, National Grid Ventures, Equinor
Develop scalable bioenergy power production with CCUS
Pilot project in progress
7 H2H Saltend Equinor Develop blue hydrogen production with carbon capture and storage in the Southern North Sea (i.e. the Endurance aquifer). Enable CO2 capture and fuel switching across the Humber industrial cluster
FEED study in progress with FID planned for 2023
8 Gigastack Ørsted, ITM Power and Element Energy
Develop green hydrogen production using offshore wind power (from Hornsea 2 windfarm)
Funding awarded by BEIS, feasibility study in progress
9 Project Dolphyn ERM Develop green hydrogen production using floating offshore wind power
Funding awarded by BEIS, FEED study in progress
1
2
3
4
56
8
9
H2
H2
CO2
H2
CO2
CO2
H2
CO2
CO2
H2
H2
Size MT10
100
1,000
CO2 Point Sources (top 50)
Saline aquifer (confined)
Saline aquifer (open)
Depleted hydrocarbon fields
Source: Adapted from: Energy technologies institute
ST FERGUS
TEESSIDE
MERSEYSIDE
HUMBERSIDE
SOUTH WALES
H2
CO2
7
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
62 63
Overall energy mixThe UK’s energy market has been transitioning to a lower carbon mix. Coal is being switched out for gas and there have been major investments in offshore wind and solar PV. In 2018, oil was still the primary fuel used for energy and its main use was in the transport sector, which accounted for over 70% of total oil demand.
Gas was the second most used fuel in the UK in 2018 and was the leading fuel for electricity generation, producing 40% of output. Gas demand has increased over the past five years as coal has been phased out. Coal is expected to disappear completely from the energy mix by 2024, resulting in gas and renewables’ share of power generation increasing (see figure 2.25). Nuclear will also account for a decreasing proportion of the energy mix as old reactors are decommissioned. Renewables are expected to see the greatest growth, especially offshore wind and solar, which are forecast to make up 50% of the power mix by 2030. Power production from other solid fuels, in the form of renewable bioenergy, is also expected to grow.
In 2018, gas accounted for 36% of the UK’s total primary energy demand, and oil 39%17. Most of the gas produced on the UKCS is delivered to the UK onshore network, the National Transmission System, and consumed domestically. When demand is low, or due to the location of certain fields, some gas is exported through interconnectors to the European market. The majority of gas is used for power generation and in the residential/commercial sector17. In 2019, over 40% of the UK’s electricity was produced using gas17. Increasing renewable generation and warmer temperatures have driven gas demand down over recent years - natural gas demand fell 4.6% between 2016 and 20172. Approximately 50% of the UK’s gas demand is met by gas from the UKCS17.
Transport makes up over 70% of the UK’s oil demand. The UK has been a net importer of oil since 2010, and output from the UKCS meets 76% of the UK’s oil demand17.
In 2010 offshore wind generated less than 1% of the UK’s electricity; by 2018 this had increased to 8%13. Offshore wind is expected to make up an increasing share of the UK’s energy mix as coal-fired power plants are phased out. It is assumed new offshore wind investments will be prioritized in policy over onshore wind and solar PV as the latter two energies transition towards more market-based forms of support, i.e. power purchase agreements (PPAs) between electricity generators and electricity providers.
Figure 2.24: UK oil production and demand (1965-2018)
Figure 2.23: UK gas production and demand (1965-2018)Figure 2.25: UK power mix- historical and forecast
Source: Wood Mackenzie, IEA
Source: Wood Mackenzie, IEA
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
64 65
ImportsIn 2018, the UK was a net importer of all main fuel types, importing 38% of its total energy supply20. The UK imports approximately 50% of its gas supply20, the majority being pipeline imports and remainder from liquified natural gas (LNG)2.
LNG imports are used as a swing fuel when either demand increases or indigenous production falls. The majority of LNG imports come from Qatar (41% in 2018), but other primary LNG sources include Russia and the US (providing 21% and 17% of the UK’s LNG imports in 2018 respectively)68. The carbon intensity of gas imported as LNG is significantly higher than the intensity of domestically produced gas. Although emissions associated with LNG imports are not directly attributable to the UK’s net zero target, they are accounted for as part of embedded GHG emissions from imported products and services. As domestic
gas production declines and LNG imports increase, the overall carbon intensity of gas used in the UK will go up. Norway is the key source of oil and gas imports to the UK, accounting for 85% of piped gas imports, while other piped gas is imported from the Netherlands and the European network via Belgium (see figure 2.26)67.
The UK imports more oil than it produces, however it also exports a large proportion of oil (see figure 2.27). This is due to the differing qualities of oil produced on the UKCS and elsewhere in the world, and the type of feedstock required by domestic refineries. In 2018, the UK produced enough oil to meet 73% of its total oil demand.17
In 2018 the UK generated 335 TWh of electricity and imported 4% - 13 TWh - of the total electricity consumed17. The UK currently imports electricity from Ireland, the Netherlands, Belgium and France via interconnectors running across the UKCS. There are plans to expand the UK’s interconnector network with new links to Norway, Denmark, France and Ireland, which are expected to become operational by 2022.
Figure 2.26: UK gas imports - 2018
Figure 2.27: UK import reliance - 2018
In 2018, renewables (hydro, wind, solar and other solid fuels) accounted for 11% of total energy consumption and 35% of total UK electricity generation. Renewable generation capacity reached 44.3GW in 201867. Electricity generation from offshore wind increased by 29% to 27TWh in 201818. Other installed renewable capacity reached 34GW in 2018, 38% of which was solar capacity and 62% onshore wind capacity.
In total, resource from the UKCS (offshore wind, oil and gas) generated just under half of the UK’s total energy demand and approximately a third of the UK’s electricity in 201817,18.
Resource from the UKCS (offshore wind, oil and gas) generated just under half of the UK’s total energy demand
Source: UK government, Wood Mackenzie
Source: IEA, Wood Mackenzie
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
66 67
2.3: Policy, regulation & commitments
Global policy The UK ratified the Paris Agreement in 2016. The Paris Agreement aims to keep the rise in average global temperature to well below 2 degrees Celsius and ideally to limit warming to 1.5 degrees Celsius, compared to pre-industrial levels.
The Paris Agreement obligates signatories to aim for the ‘highest possible ambition’ with regards to climate change.
In line with the Paris Agreement, the European Commission (EC) announced its aim to become the first carbon neutral continent by 2050. In 2018, the EU released its “Clean Planet for all” strategic framework which outlines a “direction of travel” for future EU climate and energy policies69. The European Parliament has since endorsed the carbon neutrality aim and the EC plans to propose that the 2050 target is codified, as part of the European Green Deal (the EU’s new growth strategy which aims to cut emissions whilst boosting jobs and economies70).
UK policyThe UK was the first major country to commit to legally binding emission reduction targets with the introduction of the Climate Change Act of 2008.
The act provides legally binding targets to reduce UK emissions; the initial target was an 80% reduction compared to 1990 levels by 2050, however this has since been revised to a 100% reduction in emissions by 2050. This requires the government to set binding 5-yearly carbon budgets. The UK is currently in the third budget period (2018-22). By 2032, the UK should have reduced emissions by 57% compared to 1990 levels. These targets can be adjusted according to factors such as technological progress and economic predicament.
The National Renewable Energy Action Plan (NREAP) was legislated via the Climate Change Act of 2008 and sets out renewable energy targets for 2020 as part of the UK’s contribution to EU energy targets. Under those targets, renewables should account for 15% of overall energy demand, 30% of electricity, 12% of heat and 10% of transport by 2020. Currently, the electricity target has been reached; however, the targets for heat and transport look unlikely to be met.
Each renewable source - onshore wind, offshore wind, solar and others - has individual targets.
Paris Agreement
Keep the rise in average global
temperatures to below 2 degrees Celsius.
Obligates signatories to aim for the ‘highest
possible ambition’ with regards to climate change.
UK Climate Change
Act 2008Established the Commitee on
Climate Change which recommends
carbon reduction.
Requires the government to set binding 5-yearly carbon budgets.
The UK is currently in the third budget period (2018-2022), which aims for a
37% emissions reduction by 2020.
In 2018 had achieved a 43% reduction compared to 1990 levels.
The UK government has committed by law to reduce net GHG emmissions by 100% of 1990
levels, i.e. net zero, by 2050.
The National Renewable Energy Action Plan (NREAP) (as part of EU energy targets) targets
that renewables account for 15% of overall energy demand by 2020:
30%
of electricity12%
of heat10% of transport
Sector specific targets for the proportion of energy that should be met by renewable power
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
6968
Committee on Climate ChangeAs part of the UK’s commitment to the Paris Agreement, the Committee on Climate Change (CCC), the UK’s independent climate advisory body, recommended a new target of bringing all greenhouse gas emissions in the UK to net zero by 2050. The Net Zero Emissions 2050 policy was implemented in June 2019.
The CCC further recommended Scotland target net zero emissions by 2045. Scotland previously had a target to reduce emissions of all greenhouse gases by at least 80% by 2050 relative to 1990 as part of the Climate Change (Scotland) Act (2009); however, a new Climate Change bill, which sets a legally binding net zero target of 2045, was passed by the Scottish Government in September 2019. The bill further sets an interim target of a 75% reduction by 2030, compared with 1990 levels.
To reach the UK’s net zero target emissions, the CCC is proposing an approach that combines;
• reduced energy demand through better energy efficiency and increased electrification
• increased energy production from renewable sources
• a switch to a hydrogen economy
• increased carbon sequestration through afforestation and carbon capture, utilisation and storage (CCUS)
Major technological advances will be required to implement these plans at scale and economically, especially hydrogen production and CCUS. Additionally, to achieve the net zero target, significant growth of renewable capacity is required; for example, installed offshore wind capacity will need to reach 75GW by 2050.
The CCC recommends that hydrogen use increase from current levels of 27TWh today to 270TWh in 2050: a 900% increase and equivalent to over 80% of the UK’s 2018 electricity usage17,39. To reach this target, production from reformers (i.e. SMRs and ATRs) will need to increase to a capacity of 29GW and production from electrolysis to 6-17 GW by 2050. Development of a hydrogen gas grid or alternative transportation infrastructure and carbon capture and storage infrastructure will also be required39.
To reach net zero by 2050, UK wide carbon capture and storage capacity needs to reach 176MtCO2; 46Mt for GHGs associated with hydrogen production, 57Mt for power generation, 35 Mt for bio-energy with carbon capture and storage (BECCS), 24Mt for industry and 9MT for biofuel production52. To achieve these levels, CCUS transportation and storage infrastructure will need to be developed at scale by 203052.
Resource and energy efficiency
(reduce demand for oil, gas and coal)
Electrification (particularly of transport
and heating to reduce gas and oil useage)
Develop hydrogen economy (low emmissions fuel
alternative)
Develop CCUS technology for use with bioenergy,
hydrogen and electricity production
Change land use to more emphasis on carbon
sequestration (forests) and biomass production
Societal changes to lower demand for carbon
intensive activities
Wales95%
reduction by 2050
Scotland Net Zeroby 2045
UKNet Zero by 2050
Figure 2.28: Net zero targets and priorities
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
70 71
Roadmap 2035The UK’s oil and gas industry has expertise and infrastructure key to enabling the UK to reach its net zero target. The industry therefore responded to the government’s net zero policy by developing the “Roadmap to 2035: A blueprint for net zero”. This was followed on in June 2020 with “The Pathway to Net Zero: Production Emissions Targets” which details targets to reduce emissions from upstream operations by 50% by 2030, 90% by 2040 and to reach net zero emissions by 2050115.
Developed by OGUK the roadmap outlines how the UK oil and gas industry will aim to reduce emissions associated with production activity and help develop new low-carbon technology, while also continuing to maximise production and provide significant indigenous supply to meet the country’s energy demands. The industry aims to reduce the level of offshore emissions from the 14.6 million tonnes CO2e produced in 2018 to half this in 2030 and net zero by 2050115. The emissions reduction will be measured at a basin-wide level, and not on an individual operator or asset basis, and three primary methods to reduce emissions have been identified: operational improvement, reduced flaring and venting and step-change action115. As well as emission reduction targets, the industry has set production targets, with UK oil and gas producers to aim to produce over 1 million barrels of oil and gas per day, over half of the UK’s oil and gas demand, in 2035 and extend production on the UKCS out to 2050 and beyond71. Based on current production forecast, UKCS production will be a third less than this target2.
The OGUK, through the Roadmap 2035, also highlighted how the oil and gas industry will help the UK reach its net zero target72;
• Better control of hydrocarbon consumption and emissions through reduced reliance on international petroleum imports and maintenance of indigenous production by attracting international investment, continued exploration and maximum recovery of existing resource
• Reduce emissions from production operations; primarily through electrification of platforms, the development of energy hubs and reducing flaring
• Support the development of emissions mitigation technologies, mainly CCUS and hydrogen fuel by utilising existing knowledge, skills and infrastructure within the oil and gas industry
• Invest in the expansion of low-carbon business and technologies, such as offshore wind, wave and tidal power, again using existing infrastructure, skills and knowledge within the industry
OGTC Net Zero Solution CentreTo support the Roadmap 2035, the Oil and Gas Technology Centre established a Net Zero Solution Centre in 2019.
The centre aims to investigate and implement technologies that will both reduce emissions from offshore oil and gas activities and develop new technologies that will offset emissions. A key aim of the centre is to utilise existing oil and gas infrastructure, supply chains and skills to develop new integrated energy hubs that can help meet the UK’s energy needs while also reducing emissions produced. The centre is supported by member companies including BP, Shell, Total, Wood, Chrysaor, CNOOC and is backed by the Scottish Government.
UK government CCUS deployment pathway: an action plan
• Have the option to deploy CCUS at scale in the 2030s, subject to costs coming down sufficiently
• Address policy barriers and set out policy options• Work with other governments to identify and
address barriers to cross border transport of CO2
• Deliver £4 million innovation programmes focussed on CCUS
Hydrogen Taskforce: The role of hydrogen in delivering Net Zero
• Develop hydrogen strategy within UK government• Government to commit to spending £1 billion on
production, storage and distribution projects• Enable hydrogen blending into the UK Gas
Grid and take the next steps towards 100% hydrogen heating
• Collaboration to establish 100 hydrogen refuelling stations (HRS) by 2025
UK government and offshore wind sector: offshore wind sector deal
• Increase UK content to 60% by 2030• Increase UK jobs in offshore wind to 27,000• Increase exports to £2.6 billion by 2030• 30GW of capacity by 2030*
*Target increased to 40GW by 2030 in November 2019
UK oil and gas industry Roadmap 2035
• Become a net zero GHG emissions basin by 2050• Secure at least 130,000 direct and indirect jobs• Grow and diversify energy supply chain export
revenues to £20 billion per year• Keep production output above 1 million boe
per day and meet at least 50% of UK’s oil and gas demand.
H2
Figure 2.29: Industry specific Targets and commitments
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
Sizi
ng u
p th
e U
KCS
on th
e R
oad
to N
et Z
ero
| Sec
tion
2
72 73
Closing the Gap to 2050 Technologies3
3.1: Introduction and approach to the technology roadmapThe UKCS’ role is going to be central to the UK achieving its net zero target. The UKCS is going to deliver renewable power on a scale not seen before, produce low emissions oil and gas for industry, produce clean fuels for the economy, as well as provide a source for long term carbon storage. In essence the UKCS will go beyond net zero. This will require transformational changes to the energy mix and step-change improvements in efficiencies and environmental footprints of incumbent industries, and, most importantly, integration of energy systems that are either nascent or siloed today. Achieving these goals in the next three decades will require significant research, development and scale-up efforts, with an emphasis on the key technology challenges and innovation gaps that are hampering commercial realisation. This section will explore these challenges and innovation gaps to build a net zero technology roadmap for the UKCS.
Oil and gas operators on the UKCS are already taking steps to reduce carbon emissions by improving operational efficiency, deploying lower-carbon technologies to power operations and developing next-generation tools to unlock features such as automation and predictive maintenance. These developments are, in turn, the result of increasing efforts by oil and gas operators to analyse and understand data collected through the myriad of instruments and sensors across their operations. These actions will continue to decarbonise the region while maximising its economic recovery.
However, there is an opportunity for the UKCS to not only decarbonise its operations, but also to support the UK in achieving net zero GHG emissions by 2050 (and by 2045 in Scotland). This will require significant efforts and coordination across multiple industries – incumbent and emerging, including offshore oil and gas, wind, onshore power generation, hydrogen, and many others. To decarbonise its own operations while expanding its role as the UK’s main resource base, the UKCS will need carbon storage infrastructure and increased low-carbon energy in the form of renewable electricity and hydrogen for its platforms. Many of the technologies needed are available but are often developed in industrial silos and significant innovation gaps must be addressed.
The purpose of the Technology Roadmap is to identify the most critical low-carbon technologies and the challenges that need to be overcome. Technologies will be considered as technology “families” - groups of technologies that serve a similar function - and the analysis will focus on families that:
1. Support the decarbonisation of the UKCS itself;
2. Support decarbonisation of the UK as a whole;
3. Require outsized innovation and funding support to address technology challenges and bridge innovation gaps.
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
7776
Figure 3.1: Technology families with greatest decarbonisation potential
The technology families were first prioritised based on their decarbonisation potential for the UKCS and for the UK as a whole (see figure 3.1). Those families with the greatest decarbonisation potential were selected for further analysis (see green section of figure 3.1).
With extensive inputs from key industry stakeholders, the priority technology families were systematically evaluated against two mutually exclusive sets of metrics: these considered the technology perspective (challenges, maturity, innovation momentum, commercial scaleability on the UKCS) and the ecosystem perspective (market demand, financing, dependencies and other barriers to commercialisation). The roadmap explores the key technology challenges and innovation gaps, identifies how the various technologies interlink across the wider energy ecosystem and outlines a path to advance these technologies towards a net zero energy system by 2050.
Subsea technologies
Fixed-bottom offshore wind
CO2 storage & transportation
CO2 capture
Green hydrogen
productionHydrogen
turbine
Hydrogen pipeline
Hydrogen storage
Floating solarAlternative
Fuels
Marine energy
Fuel cells
Substations
HVDC transmission
Blue hydrogen
production
Platform interconnects
Methane leakage mitigation
Flaring mitigation
UKC
S ca
rbon
aba
tem
ent p
oten
tial
UK carbon abatement potential
Platform electrification
CO2 utilisation
Geothermal
Asset monitoring
Energy harvesting
HVAC transmission
Gas-to-Liquid
Thermal energy storage
Gas compression
Gas turbines
Hydrocarbons transport
Downhole sensors
Well operations
Imaging and exploration
Net Zero Technology Roadmap approachTo identify the technologies that address these objectives, the study began with an exhaustive taxonomy of energy technologies that exist or could exist on the UKCS, compiled with inputs from technology experts on the UKCS. These included:
Source: Lux Research
Hydrate recovery
LNG
Offshore cracking/conversion
Not focus of the study
Technologies to consider supporting, but not focus
Key focus for UK and UKCS decarbonisation
Aerial wind
Floating wind
H2
H2
Low High
High
Oil and gas (drone sensors to re-usable subsea systems)
Renewables (offshore fixed-bottom and floating wind to wave and tidal energy)
Hydrogen (production, transportation, storage)
CCUS (capture membranes, calcium looping, amine scrubbers, CO2 enhanced oil recovery)
Digitalisation (digital twins, simulation tools, artificial intelligence)
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
78 79
OIL & GAS
As the energy transition progresses, hydrocarbons will still play a key role in the economy. Oil and gas operations will continue to provide secure energy sources and valuable feedstocks to produce chemicals and materials. The growing demand for hydrocarbons is palpable: according to the International Energy Agency (IEA), natural gas accounted for almost one-third of the total energy demand growth over the past decade73.
The production and transformation of energy and fuels represents a significant proportion of energy demand and emissions in the UK (see Section 2 – Carbon emissions from UKCS). However, as the offshore industry has been focusing on increasing productivity and uptime, it has also worked to upgrade and optimise operations, which in turn, has resulted in a 15% reduction in carbon intensity since 201374. For instance, operators have started implementing technologies such as digital twins, predictive analytics and digital optimisation, which help to operate equipment such as pumps, compressors and turbines at optimum efficiency. These technologies, driven by operators and technology developers, will continue to incrementally improve efficiencies and emissions.
The OGTC is currently developing an Offshore Emissions Reduction Solutions report, due for publication in 4Q 2020. The report will provide details on a range of crucial short, medium and long-term quantified measures that UKCS oil and gas operators can implement to reduce the carbon intensity of their offshore assets. This report will importantly reflect the knowledge and practices of the operators and supply chain who are driving the energy transition on the UKCS.
The OGA’s UKCS Energy Integration407 report, highlights the importance of energy integration for the oil and gas sector in reducing production emissions, as well as accelerating the progress of CCS and hydrogen in support of net zero.
The implementation of more revolutionary solutions has, however, been hampered by the overall maturity of the basin and limited availability of capital due to low oil prices. In this section, we will explore the decarbonisation solutions that require more support from industry – those that might have been set aside because of high technology hurdles, or those that need more government support and inter-industry collaboration. These can broadly be categorised as: platform electrification, mitigation of flaring and methane leaks and subsea systems.
Emission reduction technologies
3.2:
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
80 81
Platform electrificationToday, 74% of CO2 emissions offshore come from combustion equipment that either provides electrical power to platforms or drives mechanical loads such as compressors75. Electrification of offshore oil and gas installations can significantly reduce emissions in two main forms: first, by supplying low carbon electricity from renewables to existing electrical loads; secondly, by potentially replacing open cycle gas turbines that drive mechanical loads with electric motors.
Current status
Power demand from UKCS platforms is approximately 24 TWh/year. This represents over 8% of total UK power demand and accounts for
Figure 3.2: Platform electrification scenarios
over 10% of total power plant emissions76. Due to platforms’ remote locations, this demand is usually met by gas turbines – using wellhead gas – and diesel generators. However, open cycle gas turbines are inefficient (typically in the 28% to 38% range, depending on the load, with lower efficiencies often observed on platforms in the UKCS77) and result in high CO2 emissions. A platform with an output capacity of 100MW would emit over 620,000 tonnes of CO2 per year.78.
Platform electrification can be either full or partial. Full platform electrification replaces gas turbines and diesel generators with electricity from onshore generation or from offshore wind farms. This also requires heat generation and high-power mechanically-driven equipment like gas compressors to be replaced to run on electricity, which leads to high capital costs, as well as to footprint and weight challenges. Partially electrifying is a nearer-term alternative, where gas turbines continue to cover high-power mechanical loads, while remaining processes use electricity. Though partial electrification can already reduce CO2 emissions by a third79, using alternative fuels like hydrogen or ammonia in gas turbines can further amplify carbon savings while overcoming space and weight constraints on offshore platforms where full electrification is not feasible. (see section 3.4 - Hydrogen technologies).
Technology challenges
The business case for platform electrification depends on platform conditions and location, as well as timing of cessation of production. Connecting onshore power to offshore platforms involves a significant investment, as platforms on the UKCS are often more than 200km from shore. To justify infrastructure outlay, new platforms are generally more suitable for electrification, though factors such as the overall power consumption, types of loads and platform size will have an impact on the decision to electrify. For existing facilities, electrification will only be viable if the savings in operating costs - resulting from increased uptime and reduced maintenance costs - compensate for the high cable and platform conversion investments as well as the lost earnings from production downtime – in the case of full electrification – while transitioning to an electrified platform. Electrifying a cluster of fields helps to share these capital costs.
A study by the Norwegian University of Science and Technology estimated the capital expenses to fully electrify the Utsira area in the Norwegian continental shelf – consisting of the Edvard Grieg, Johan Sverdrup, Ivar Aasen and Gina Krog fields – were approximately £1,150 million80. The study assumes the use of onshore power, meeting heat demand with electric heaters and an AC transmission system. A partial electrification project relying on gas turbines for high-power equipment such as compressors as well as using waste heat to supply heat demands could have capital expenses of nearly £750 million80. Though cost reductions in subsea cabling, power electronics, and compressors using electric drives are needed to speed up the adoption, platform electrification was shown in the same study to reduce operational costs by nearly 45% at periods of high energy demand80.
Source: Adapted from OGA image
1. Power from shorePlatform
Substation
Gas field
UK
2. Power from interconnectorsPlatform
Substation
Gas field
UK
3. Power from windfarmsPlatform
Substation
Gas field
UK
Power transmissionSubsea cabling costs are high and range from £1 million per km to £2 million per km, depending on the voltage rating and the level of inclusion of electrical equipment such as power converters.81. Electrification projects will therefore benefit from developments that lower the costs of subsea cabling while ensuring that these are robust enough to withstand harsh conditions on the seabed82. Platform electrification stands to benefit from developments in the offshore wind energy sector, which maintains a sharp focus on reducing cabling costs.
Electrification costs also depend on the type of power transmission system used. Platforms connected to onshore power in the Norwegian North Sea demonstrate feasibility for both high voltage AC and DC transmission83. DC transmission will be a more cost-effective solution for distances higher than 100km due to lower line losses than AC systems84,85. However, converting onshore AC power to DC power for transmission and back to AC power for usage can cost approximately £0.2/W depending on voltage and power rating, which can add up to a capital cost of £100 million for two 250 MW conversion stages86,87. Furthermore, the power electronics equipment necessary to convert onshore frequency of 50Hz to the operating frequency of 60Hz in the North Sea basin creates further challenges with respect to the available space on platforms.
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
82 83
An additional consideration for projects with power from shore – either through wind farms or direct connection to an onshore grid – is the potential strain that electrified platforms can put on onshore power grids. This can result in the need for grid upgrades, leading to additional costs for platform operators.
Space constraints also play an important role. A study in the Netherlands assessed the electrification potential of three platforms (K5, K14 and P15) and found that the required deck space varied from four to seven 40-foot containers depending on power demand88. With space at a premium offshore, power electronics need to reduce converter footprint - including that of associated cooling systems - while maintaining the high conversion efficiency of larger equipment. These developments can enable broader uptake of platform electrification. In this regard, companies such as QL Tech have started to develop concepts of converter stations that are 10 times smaller than existing systems. Similarly, the development of subsea substations represents another technology alternative tackling the issue of limited space on offshore platforms.
Electrification of equipmentGas compressor systems dominate platform energy consumption89. In the UKCS, a third of the gas turbines in operation drive mechanical compressors90. Although installing electric motors in place of gas fired turbines can result in operational efficiencies and lower maintenance costs, the capital costs, weight and size of high-power electric motors are significantly higher than those of gas turbines91. This can limit the potential for electrification to lower power systems (below 15 MW92). Replacing natural gas with low-carbon fuels like hydrogen or ammonia can provide a decarbonisation pathway for platforms where switching from mechanically driven compressors is not feasible (see section 3.4 - Hydrogen technologies).
Table 3.1: Options to electrify platforms
Table 3.2: Technology challenges of platform electrification
Solution Benefit Challenges
Option
1Use existing subsea interconnectors
Reduced capital expenses as shorter subsea cables are needed.
Lack of infrastructure in most key producing areas in the North Sea. Link connections to existing subsea interconnectors have not been deployed93. High cost of switch gear and substations.Regulated energy markets.
Option
2Offshore wind turbines: these can share the same transmission infrastructure that connects wind farms to shore.
Platforms could benefit from wind power in periods of high wind while relying on onshore power generation or their own gas turbines in periods of low wind.
Creates the risk of adding load to a potentially strained onshore grid in periods of low wind.
Option
3Connecting multiple platforms to dedicated offshore wind farms in a microgrid configuration.
Companies could potentially share capex and opex for power distribution infrastructure, while reaping electrification benefits.
Dedicated backup generation or energy storage is required.
Option
4Mobile power generation units such as floating wind turbines.
Mobile generation can help electrify small fields on a temporary basis before being re-located to other platforms.
High capex of floating generation units (see section 3.3 - Renewable energy technologies). Local, or mobile, energy storage capacity necessary as back-up power.
PLATFORM ELECTRIFICATION INNOVATION GAP
Subsea cables and HV substations: high capital costs of strong and reliable (static and dynamic) installations
Temporaryelectrificationsolutions: high capital costs and footprint to electrify ageing platforms and small fields
Disconnection & reconnection: lack of fast connection solutions that enable on-demand electrification of floating structures
Critical gap, unlikely to be resolved without strong effort Needs additional effort On track to be resolved
Emerging solutions for electrification of platformsThere are four options to reduce capital expenses associated with platform electrification from onshore power (see table 3.1).
Supplying the high power demand of platforms solely through wind power will require energy storage capacity to be installed either at the platform or nearby on fixed or floating platforms. Alternatively, backup gas turbines or diesel generators would be needed to continue to supply power during times of low wind. This could also have an impact on how much electricity could be used, as specific equipment such as compressors require a constant and reliable power source. However, the use of this hybrid solution using both wind power and gas-fired generators will be restricted to facilities where electric motors already drive the main loads in platforms. Finally, the use of wind power will also require the implementation of load management controls to ensure reliable operations.
Electrifying platforms using floating wind turbines that can be relocated on-demand will require technology to be developed that will allow floating structures to be quickly disconnected and re-connected. Further development of dynamic cabling technology is needed to lower costs while ensuring that fatigue-prone components, like the external sheath, can withstand the high loads of waves, ocean currents and the floating structures for longer times94. Likewise, cost reductions in the manufacture of floating structures, which can potentially be achieved through economies of scale, can contribute to the deployment of floating wind-powered platforms.
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
84 85
Accelerators, enablers, and interdependent technologies
There are several system-level interdependencies of electrifying platforms. Four stand out:
1. Offshore wind: using wind farms currently connected to onshore grids to power platform operations can avoid production curtailment in periods of high wind.
2. Hydrogen production: electrification could potentially enable the re-use of old platforms as hydrogen hubs, where electricity is used to power electrolysers for hydrogen production and subsequent storage and transportation. This model
Table 3.3: Electrification projects to date and planned
Operator Equinor Equinor Neptune Energy Equinor Equinor Aker BP Equinor Total Shell BP BP
Offshore field name
Johan Sverdrup (Phase 1)
Martin Linge Q13A-A* GoliatJohan
Sverdrup (Phase 2)
Valhall Troll B and C97 Elgin- Franklin98 Shearwater98 ETAP98 Clair99
Country Norway Norway Netherlands Norway Norway Norway Norway UK UK UK UK
Basin Northern North Sea
Northern North Sea
Southern North Sea
Barents Sea
Northern North Sea
Central Graben
Northern North Sea
Central North Sea
Central North Sea
Central North Sea
West Shetland
Planned date 2019 2018 2018 2016 2022 2011 - 2023 2023 2023 -
Power transmission system DC AC AC AC DC DC - - - - -
Cable length 200km 162km 14km 106km N/A 292km <100km >200km >200km >200km >75km
CO2 reduction (MT/year) 620,000MT 200,000 MT12 16,500 MT 80,000 MT95 N/A 300,000 MT96 - - - - -
Several electrification initiatives are already underway or in the planning phase (see table 3.3), highlighting the feasibility of electrification from onshore power. However, advancing electrification projects relying on offshore wind power will require careful coordination between stakeholders. Industry players who are collaborating to establish offshore grids should consider offshore wind capacity coming online, oil and gas production forecasts, power needs for offshore assets and the possible repurposing of old platforms for other applications such as hydrogen production and CCUS.
would only be applicable to the few platforms with optimal locations; i.e. those in the vicinity to shore, other platforms or wind farms (see section 3.4 - Hydrogen technologies).
3. Subsea production: for subsea systems to realise their full decarbonisation potential, electrification of subsea equipment with low-carbon electricity is critical.
4. Energy storage: Energy storage can further aid in the decarbonisation of platform operations in the context of electrification. While widespread deployment of batteries is a challenge due to space and weight constrains, batteries have the potential to replace generators operating as spinning reserves. In this case, batteries can supply electricity to the platform while back up generators are brought online.
Cluster development
* PosHydon project testing the concept of an integrated energy system
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
86 87
Technology challenges
There are several sources of flares and vents including: base load flares, which result from the gas used for safe and efficient operation of the process facility and flare system; flaring from operational or mode changes, which includes flaring from the start-up and planned shut down of equipment during production; flares from emergency shut down or process trip of equipment; and unignited vents, which includes inert gases and hydrocarbon gases that may be discharged to an atmospheric vent from e.g. oil storage tanks108. The production of associated natural gas in oil production operations also results in flaring and venting. It is estimated that ~3% of associated gas produced is flared and vented109.
Associated gas is highly variable in flow and composition, making any kind of technology-driven mitigation very challenging. Despite this, platforms in Norway have achieved zero routine flaring - with policy playing a crucial by ensuring that the field developments were designed to prevent routine flaring.
Norway introduced a total ban on non-emergency flaring in the Norwegian continental shelf in 1971, requiring oil and gas producers to present gas utilisation plans before developing fields, while mandating thorough monitoring and reporting systems. Later, the country introduced a carbon tax and trading scheme, calculated based on the flared and vented volumes and reaching a rate of £95 per 1,000 cubic metres102. These policies prompted companies to plan pipeline networks to transport associated gas. For example, the Draugen field re-injected associated gas into a nearby aquifer for three years while a gas export pipeline became operational; such planning was crucial for field development to obtain regulatory approval103.
Flaring and venting mitigationFlaring and venting are two ways operators dispose of associated natural gas, typically for operational, safety, or economic reasons. Venting is often the result of an emergency pressure release while flaring is a carbon-intensive combustion of principally methane and is the most economical way for operators to dispose of low-value associated natural gas.
Current status
According to the IEA, approximately 4,950 billion cubic feet (bcf) of gas is flared each year around the globe100. The OGUK “Environment Report 2019” stated that over 49 bcf of gas were flared on the UKCS in 2018, a 6% decrease on 2017. On the other hand, 3,900 million cubic feet (mmcf) of gas were vented in the same year, a 53% increase from 2017101. In total, flaring and venting accounted for approximately 29% of the UK’s upstream production CO2 equivalent (CO2e) emissions4. Mitigating routine flaring and venting of natural gas, as well as limiting methane emissions from incomplete combustion in flares and gas turbines could contribute significantly towards reducing emissions.
63%
Turbines
Engines
Heaters
Venting
Flaring
Other
1%
5%
2%5%
24%
Source: OGUK
Associated gas re-injection has become commonplace in Norwegian fields. Common re-injection methods include water-associated gas (WAG) and miscible injection that are used for enhanced oil recovery (EOR). However, the effectiveness of associated gas re-injection as a sole strategy to avoid flaring is limited due to factors such as high energy requirements for re-injection, high reservoir pressure, different permeability in the reservoir, risk of hydrate formation104 and the need for more capital equipment to be added to a platform. Furthermore, the availability of natural gas re-injection equipment on a platform does not guarantee a reduction in flaring. In fact, a study by the University of Edinburgh found that platforms on the UKCS fitted with re-injection systems saw no significant reduction of flaring rates compared to platforms with no re-injection infrastructure105.New platforms on the UKCS already avoid flaring for gas disposal. For more mature fields, using waste gas to generate electricity could help to mitigate flaring.
Accelerators and enablers
As part of the World Bank’s Global Gas Flaring Reduction Partnership, companies and governments are targeting the eradication of routine flaring, when it is economically viable, in existing fields by 2030110. In the “Roadmap 2035” report, OGUK already states the industry’s commitment to supporting the initiative111.
Nonetheless, Norway’s progress highlights that policy changes – and not technology – are the main driver to reduce or eliminate flaring. Installing high precision systems to measure flaring and venting emissions is a key first step towards reducing such activities. Similarly, setting industry-wide mandatory targets to reduce flaring and venting, as well as accompanying measures to ensure compliance, are key to adoption.
Figure 3.3: Upstream greenhouse gases emission sources
14.6MtCO2e
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
88 89
systems can detect large leaks, but have limited ability to detect small, chronic leaks. Dynamic modelling is a promising way to detect leaks in both surface and subsea pipelines. It continuously measures the discrepancy between measured data and simulated values based on statistical and fluid flow models. Implementation has been limited because of the high computational demands118.
In the case of external systems, restrictions include their limited sensing range, difficulty in quantifying the size of leaks, vulnerability to ocean currents and susceptibility to false alarms119. A promising external system that can potentially enable real-time monitoring is fibre optic leak detection. The technology has the potential to detect and locate small leaks accurately by measuring changes in temperature along pipelines and capturing the acoustic signature of leakage fluids. Currently, the technology remains at an early development stage for offshore environments due to high installation costs and costly peripheral equipment120.
Operations and maintenance service providers need to integrate sensors in ROVs, AUVs and UAVs. The technology itself could be restricted by bad weather conditions and the travel range of these vehicles is restricted by the limited energy densities of the batteries powering them.
Methane leak mitigationMethane is estimated to have a global warming potential 28 times higher than CO2 over 100 years. Oil and natural gas operations alone accounted for approximately 82 million tonnes of methane emissions in 2019112. Key sources of methane emissions include leaks from pipelines, compressor stations, storage tanks, and natural gas processing plants and leaks at metering and regulating stations76.
Current status
The IEA estimates that methane emissions from oil and gas production and processing in the UK reached approximately 334,000 tonnes in 2019, with offshore operations being responsible for nearly 129,000 tonnes114. Measures for methane emissions abatement are well-known, and include the installation of vapour recovery units as well as the replacement of compressor seals. However, fugitive emissions - or leaks - are an important fraction of the methane emissions on the UKCS. The IEA estimates that methane leaks accounted for nearly 29,000 tons, or 0.7 MtCO2e/yr; yet, a recent study from Princeton University suggests that fugitive emissions could be double the IEA estimate113. A key measure to tackle these emissions involves the implementation of leak detection and repair programmes.
Figure 3.4: Methane abatement costs
Leak detection and repair programmes are common practice among operators. While some detection methods rely on human operation, which results in longer detection times, new internal and external systems have emerged to quickly and accurately detect leaks of different sizes in different environments. Internal sensors are installed across pipelines or pipeline terminals to monitor parameters such as pressure, temperature, flow rate and sonic velocity inside equipment and pipelines116,117. This data helps determine flow conditions and potential losses. External systems measure physical properties around equipment and can more rapidly detect and locate smaller leaks than internal systems. This includes sensors for capacitance, temperature differentials, acoustics and optical signatures. External sensing can be integrated in remotely operated vehicles (ROVs), or autonomous underwater vehicles (AUVs) to detect leaks subsea. Conversely, unmanned aerial vehicles (UAVs) can be mounted with sensors to detect leaks from topside equipment.
Technology challenges
Offshore leak detection faces many challenges because of harsh environmental conditions, which lead to poor system accuracy. For example, internal
Table 3.4: Technology challenges of methane leak detection
METHANE LEAK DETECTION INNOVATION GAP
Resilience: sensors that withstand harsh environmental conditions
Sensorflexibility: accurate detection of all types of leaks
Sensor range: sufficient coverage per sensor to minimise number required
Critical gap, unlikely to be resolved without strong effort Needs additional effort On track to be resolved
Source: IEA
-10
-8
-6
-4
-2
0
2
0 10 20 30 40 50 60 70 80 90
kt of methane
Net
sav
ing
(GBP
/mm
btu)
100 110 120
Offshore oil - Replace with instrument air systems Offshore gas - Replace with instrument air systems
Offshore oil - Vapour recovery units Offshore gas - Vapour recovery units
Offshore oil - Upstream leak detection and repair Offshore gas - Upstream leak detection and repair
Offshore oil - Install flares Offshore gas - Install flares
Net
cos
t
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
90 91
Subsea technologiesCurrent status
Subsea technology has been a key focus for operators on the UKCS and wider North Sea since the 1960s. The basin has been a global leader in innovation, with more than 250 subsea systems deployed to date121. Subsea production has the potential to be more energy efficient than conventional upstream facilities on platforms or floating production, storage and offloading (FPSO) units122, partly due to the electrification of power-consuming components like compressors. Ultimately, subsea factories are the final frontier of subsea technology development. This concept involves a standalone subsea production system on the seabed conducting operations like single-and multi-phase boosting, gas compression, gas-to-liquid and liquid-to-liquid separation, as well as water re-injection. Subsea factories thus have a high decarbonisation potential123.
Subsea factories could transform traditional offshore spend by eliminating large offshore platforms altogether, replacing them with simpler floating structures limited to atmospheric pressure operations like oil-gas separation. Aker Solutions, Atkins Global and Crondall Energy are examples of
companies developing such reusable production buoys124,125,126. Given the maturity of the UKCS, the potential to eliminate topside platforms is largely limited to new developments. However, subsea factories can also enable the development of over 300 small pools on the UKCS through subsea tie- backs of these marginal fields to existing platforms – or to floating hubs - in the future. The use of subsea equipment for small fields opens the door to the re-use of equipment once a reservoir has been depleted, as individual equipment can be removed from the seabed, refurbished as necessary and placed on a new field127,128. Nevertheless, the re-use of equipment not specifically designed for a reservoir could result in reduced operational efficiency, and so how this impacts emissions will need to be taken account of.
Individual subsea technologies that improve the efficiency of oil and gas production processes – ranging from subsea wellheads to boosting and injection systems – have already been deployed globally, with companies such as TechnipFMC, Aker Solutions and OneSubsea standing out as key developers. However, subsea compression and power distribution are two key technologies under development that can unlock greater decarbonisation potential on the UKCS:
• Subsea compressors are more energy efficient than their platform counterparts. On the seabed the back pressure is lower than on the
platform and so the same production rates can be sustained but using less power. Aker Solutions recently showed that the overall energy consumption of a subsea compression system can be up to 38% lower than topside compression over the lifecycle of the system129. An additional advantage of subsea compression is its potential to extend plateau production of a well due to a lower pressure drop in pipelines downstream. Fields with a projected decline in reservoir pressures could thus benefit from subsea compression57.
• Subsea substations are key to supplying power to factories on the seabed without relying on increased riser capacity while alleviating the need for topside space130. These will enable subsea networking and integration of oil and gas with renewables, either off- or onshore.
• Though technologies such as subsea pumping or subsea oil storage are also of high relevance to move topside operations to the seabed and so help to unlock marginal oil fields in an economic manner, the impact of these technologies on decarbonisation is lower than that of subsea compression or distribution systems.
Technology challenges
Subsea compression has long been a development target in the industry. It was first deployed in 2015 at Equinor’s Åsgard field in the Norwegian continental shelf, using technology developed by Aker Solutions and MAN. Later, companies such as Shell and Chevron started to implement the technology at the Ormen-Lange field in the Norwegian continental shelf and Jansz-Io field in Australia, respectively131. Currently, the technology relies on encasing compressors with their high- speed drives in hermetically sealed, pressurised containers132 - which makes it an expensive solution. However, Aker Solutions and MAN continue to optimise the technology, claiming that capital expenses and installation costs could eventually be 50% of what they are today133.
Subsea substations are currently under
Figure 3.5: Multiple technologies can combine for subsea operations
development, with no systems deployed commercially. A key challenge is the design of electronics with materials resistant to pressurised environments.
Cooling systems that can guarantee the thermal performance of the electronics is another important challenge134. However, Siemens and ABB recently completed testing their respective pressure- compensated subsea distribution systems that incorporate transformers, variable speed drives and switchgears, as well as power electronics135. Both systems are expected to require significant capital expenditure, although ABB claims that its technology can offer capex savings of more than £400 million if eight loads – such as compressors or pumps – are networked through a single cable136.
The UKCS has a unique opportunity to leverage subsea equipment to tap underexploited small pools and unlock low-carbon production of precious, but otherwise expensive, resources. The first goal is to build reusable subsea equipment with easy disassembly and re-assembly – an important target for the dozens of developers already working on subsea systems137. In addition, designing subsea equipment that ties together floating hubs with oil processing units will help to make the idea of subsea tie-backs of small pools a reality. Designing equipment for integration with technologies such as offshore wind farms, subsea electrolysers and fuel cells (see section 3.4 - Hydrogen technologies) will also be of paramount importance to improve the decarbonisation potential of the UKCS.
Subsea compression and distribution technologies (among others) still need to demonstrate their long-term reliability and achieve significant cost reductions. However, there are no obvious technology gaps in the long term to get to a “subsea future”. Operators like Equinor, BP, Total and Shell and technology developers like Aker Solutions, Man, TechnipFMC, OneSubsea, ABB and Siemens are already driving this development across the globe. These ongoing collaborations are likely to result in more robust designs that could be commercial in the mid-term.
Gas injection
Produced water injection pump
Sea water injection template with pumping
Oil storage
Gas, oil, produced water separation
Power distribution and control
Manifold
Oil export
Gas export
Gas compression
Source: Wood Mackenzie
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
92 93
Table 3.5: Technology challenges of subsea technologies
Technology accelerators and enablers
One of the main reasons for high costs in subsea installations is due to operators working with suppliers to produce tailormade solutions on a project-by-project basis. The industry is currently exploring standardisation, which will help reduce capex and project development time. DNV-GL is currently managing several joint industry projects to standardise different elements of subsea systems, such as subsea welding, testing of forgings and specifications for subsea pumping systems to boost operations138. Similar initiatives will be needed to deploy reusable equipment for marginal fields on the UKCS.
Oil and gas ecosystem and path to 2050 In the near-term, the decarbonisation of the industry will continue to rely on the implementation of technologies to improve the operational and energy efficiency of the UKCS. Digital technologies will play a key role as enablers of such efficiency improvements. The widespread rollout of new technologies will require sustained development efforts, industry collaborations and policy support. Yet, technologies such as platform electrification and subsea production systems can have an impact beyond CO2 emissions reduction by helping unlock the remaining reserves on the UKCS.
Initial UKCS electrification projects will rely on onshore power and partial electrification will be an attractive lower-capital option for existing platforms on the UKCS. Using onshore power for existing early life or new developments will be key for oil and gas companies and suppliers to better understand the infrastructure and equipment changes required for electrification. However, the implementation of any electrification project will continue to depend on the location, productivity and age of a platform, despite the potential for lower lifetime operational expenses and CO2 emissions80. Similarly, electrification with power from shore will be dependent on low-cost electricity from renewables. Multi-variable scenario-based models to clearly visualise potential returns on investment of electrification projects will be important decision support tools. Wider deployment of electrified platforms with onshore power will be contingent on reducing capital costs of AC and DC subsea cabling and high-voltage substations and on reducing their footprint. A key consideration is that for the UKCS, deployment of electrification projects will only occur in the mid term as supply chains are not assembled, the legal framework to implement electrification projects is not developed on the UKCS, and the installation of electrification infrastructure can take up to seven years for full electrification projects.
SUBSEA TECHNOLOGIES INNOVATION GAP
Subsea equipment: high capital costs and installation costs
Resilient materials: electronics that operate under high pressure conditions while maintaining thermal performance
End-of-life design: subsea equipment that can be re-used and integrated with renewables
Critical gap, unlikely to be resolved without strong effort Needs additional effort On track to be resolved
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
94 95
In the mid-to-long term, offshore wind developments should have unlocked the first few offshore energy hubs, enabling electrification of nearby platforms far from shore – where installing subsea cables becomes economically unfeasible – and offer additional flexibility and risk mitigation to the energy system. Development of lower cost and reliable dynamic interconnects, as well as rapid disconnection and reconnection technology, can eventually enable floating wind farms to electrify platforms on demand. These developments will also benefit the development of subsea factories, which rely on electrification to realise their decarbonisation potential. To enable these developments, regional stakeholders will need to address regulatory barriers around ownership and operation of integrated energy systems.
To mitigate methane emissions, near-term actions include the reduction of venting and methane leaks through the replacement of seal systems and equipment prone to leaks, including pumps, valves, storage tanks and compressors. More frequent inspection programmes using available leak detection technologies such as infrared or ultrasonic systems can help prioritise which equipment to retrofit. After 2030, broad-scale continuous monitoring equipment and sensors will be required to quickly address leaks, while avoiding recurrence of leaks at the same locations. Industry will need robust integrated sensing systems that are able to continuously monitor equipment for leaks of all sizes with high spatial accuracy and a sufficiently long range to limit the number of units needed for overall systems-level capex reduction. For places where sensor coverage is poor, the industry will need to deploy UAV, AUV and ROV technologies to pinpoint the location of leaks and repair them. While technology has a role to play, strong regulatory frameworks, compliance protocols and industry commitment are crucial to promote methane leak and flaring mitigation. Building more comprehensive emissions tracking is a key step towards the quantification of methane emissions and efficacy of leakage detection and mitigation technologies. While near-term alternatives such as gas re-injection and microturbines exist, the high variability of associated gas and reservoir conditions will limit the impact of these technologies, especially in ageing platforms.
Leading operators like BP, Equinor, Shell and Total are already investing in developing subsea technologies. As developments continue to bring down costs, the UKCS can take a lead on the integration of subsea technology with unmanned floating topside systems. This will not only help in achieving decarbonisation objectives, but also create opportunities to economically recover hydrocarbons from small pools with reusable equipment that can connect to such floating structures. In order to achieve this, the industry will need to establish standard testing protocols to optimise the certification and deployment of subsea equipment that can be easily connected to energy generation assets and even to other floating production hubs. Towards 2050, subsea systems can then become the preferred option for new discoveries because of their ability to avoid the installation of costly topside infrastructure. Finally, as the industry’s understanding of subsea operations deepens, hydrogen production, storage and usage operations can also start moving to the seabed to enable further integration of the oil and gas sector with other low-carbon sectors.
Speculative technologies for oil and gasDownhole hydrogen production139
• Generate and separate pure hydrogen via in situ autothermal reforming of either
crude oil or natural gas, or both, in depleted oilfield reservoirs.
• Produce hydrogen via existing oil and gas wells while leaving all hydrocarbons in the subsurface. The process only generates clean water and energy as by-products and therefore there are limited emissions associated with the process.
In the mid-to-long term, offshore wind developments will unlock energy hubs, enabling electrification of nearby platforms far from shore
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
96 97
Oil and gas technology roadmap
Short-term Mid-term Long-term
Temporary electrification solutions: high capital costs and footprint to electrify ageing platforms and small fields
Ecosystem
• Multi-variable scenario-based models to clearly visualise potential ROIs of electrification projects will be important decision support tools
• Standardisation of subsea equipment to reduce capital costs and project development time
• Development of clear tracking and reporting systems for flaring and venting emissions
• Establishment of strong regulatory frameworks, compliance protocols, and industry commitment to promote methane leak mitigation and flaring mitigation
Ecosystem
• Standardisation of subsea equipment to enable re-use in multiple fields
• Addressing regulatory barriers around ownership and operation of integrated energy systems
Ecosystem
• Oil and gas systems fully integrated with offshore renewable power system
• Subsea factories with significantly reduced surface footprint• Unmanned re-usable production systems for small
pools deployment
Subsea cables and HV substations: high capital costs of strong and reliable (static and dynamic) installations
Disconnection & reconnection: lack of fast connection solutions that enable on-demand electrification of floating structures
Resilience: sensors that withstand harsh environmental conditions
Resilient materials: electronics that operate under high pressure conditions while maintaining thermal performance
End-of-life design: subsea equipment that can be re-used and integrated with renewables
Sensor flexibility: accurate detection of all types of leaks
Subsea equipment: high capital costs and installation costs
Sensor range: sufficient coverage per sensor to minimise amount required
“incremental gain” tech challenges that will get resolved with or without
dedicated effort
Subsea technologies
Methane leak detection
Flaring mitigation
Critical path
Parking lot
Natural gas re-injection
Figure 3.6
Source: Wood Mackenzie, Lux Research
Platform electrification
2020 2035 2050
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
98 99
RENEWABLESRenewable energy sources will play a key role in reducing emissions in the UK and are critical components of the CCC’s Further Ambition scenario. Offshore wind is the biggest contributor with a pipeline of 43 GW and around another 20 GW in upcoming lease zones140.
To achieve the CCC’s vision, a fully integrated renewable energy ecosystem, which includes the necessary transmission and storage infrastructure, is crucial. This ecosystem can unlock the potential of industry electrification and green hydrogen to further lower the carbon intensity of the UK’s energy and power mix.
3.3:
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
101100
Fixed-bottom offshore windCurrent status
The UKCS currently has around 35% of the global installed offshore wind capacity and 45% of Europe’s, almost exclusively from fixed-bottom turbines141. Larger blades, turbines and hub heights have increased power ratings and capacity factors which, along with improvements in cable power ratings, installation experience and the development of a local supply chain, have dramatically reduced in cost.
The clustering and extension of existing projects on the UKCS allows operators to share resources and assets which helps to make upgrades cost-effective. At the same time, offshore wind technology continues to evolve, with key developments including:
Table 3.6: Key developments in wind
Technology challenges & accelerators and enablers
System sizes: Larger blades and taller towers can increase wind turbine capacity and economic feasibility, while new materials allow for lighter and longer blades (see figure 3.7). Material choice is increasingly shifting from glass- to carbon-fibre composites. For example, Saertex’s150 carbon fibre-reinforced spar caps reinforce blades lengthwise151,152.
Figure 3.7: Trends in designing wind turbine blades
Larger blades, taller towers and bigger turbines to increase capacity factor.
Most of the UK’s future installed capacity will be fixed-bottom turbines. To maximise potential, blades are getting longer, and hub heights are increasing. With a rated capacity of 12 MW and 63% capacity factor in North Sea wind conditions142, GE’s Haliade-X is currently the largest wind turbine on the market, with
107 m blades and a 260 m high tower143
Currently being tested in the UK144, GE plans to produce the first commercial units by mid-2021.
Airborne systems to increase altitudes.
Higher altitudes have higher wind speeds; airborne energy systems (AES) use a tethered kite or a drone, fly at heights of 150 m to 300 m and can reach capacity factors of up to 70% using less material than turbines. AES is less mature than conventional wind power and improvements in fixed and floating turbines have been limiting the role it can play. After Google shelved the Makani project in February 2020149, developers are cautiously progressing by testing prototypes. One prominent example is Ampyx Power’s plans to launch a
150 kW prototype together with RWE
Floating foundations to operate in deeper water.
About 80% of the UKCS’ offshore wind resource potential is at depths greater than 60 metres, where fixed-bottom systems are no longer practical145. Floating foundations can be used at any depth and unlike fixed-bottom, do not require bespoke foundation design for each location146, making standardised assembly possible to significantly cut costs. The largest floating wind project operating today is Equinor’s 30 MW Hywind Scotland project, however several projects are set to surpass this size, such as the 50 MW Kincardine wind farm - scheduled to be completed in 2020 - and Equinor’s 88 MW Hywind Tampen147 which will also be used to electrify offshore oil and gas platforms.
10 GW of floating offshore wind capacity installed on the UKCS by 2050148
Source: Wood Mackenzie
GlassCarbon
83%
All the offshore turbine blades installed in 2019 are glass fibre except for MHI Vestas’ 80m blades on the V164. • However, the learnings from the V164 are being
leveraged on V174 blades• A focus on minimising loads and using
aerodynamically enhanced aerofoils results in only a marginal increase in blade weight from 34 tons to 35 tons
99%17%
2019 2028
• Turbine OEMs shifting to carbon fibre blades; notably SGRE is shifting resins on its SG 193-DD for the first time to use carbon.
• Chinese OEMs are also seeking slender carbon blades for lower wind offshore conditions in China
1%
80-89.9m
90-99.9m
110-119.9m
120-129.9m
120-129.9m
130-139.9m
140-149.9m
100%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
50-59.9m
60-69.9m
70-79.9m
Blade length trend
Turbine material trend
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
102 103
Offshore wind turbines are subject to a host of complex forces. That makes designing ever larger, yet durable and reliable systems an even greater challenge. Foundations need to better stand up to long term hydrodynamic loads and designs require novel nacelles and larger rotors. The models that can predict the load distribution and failure modes are valuable tools to develop more reliable designs153.
Large turbines have additional operation and maintenance costs. To bring these down, several developers are working on novel coatings to prevent and delay blade erosion, magnetic gearing, technologies to make part replacement easier, and acoustic emission monitoring to safeguard structural integrity. Unmanned aerial vehicles, for example those produced by ZX Lidars154, can be used for blade inspection and predictive maintenance to further reduce maintenance costs and extend wind turbine lifetimes.
Table 3.7: Technology challenges of fixed-bottom wind turbines
FIXED-BOTTOM WIND TURBINES INNOVATION GAP
Larger blades: advanced carbon fibre-based composites enabling easier to recycle, yet longer blades, and thus larger capacities
Wind turbine decommissioning: removal, transportation, and recycling of older turbines, including recycling of blades
Taller towers: novel designs and materials to increase the hub height
Increased rotor diameters and nacelle designs: to enable larger turbines
Blade leading-edge erosion: novel materials and coatings to prevent erosionand maintain smoothness for high efficiency
Magnetic gearing: remove mechanical gears to reduce lubrication and risks of having to replace multi-ton gearboxes via floating cranes if these fail under high-stress wind conditions.
Acoustic emission condition monitoring: maintenance control of the structural integrity
Automated inspection: unmanned aerial vehicles for inspecting blades
Unmanned installation: remote onshore control of transporting and installing wind turbines
Critical gap, unlikely to be resolved without strong effort Needs additional effort On track to be resolved
Decommissioning: At the end of service life, decommissioning and restoration activities require the removal of all physical material and equipment. The concrete foundations used to anchor the wind turbines are difficult to fully remove. Also, dust and toxic gases may be released during the removal of the rotor blades. Given the massive size and inconvenient shapes of these components, they need to be cut or demolished before transportation. Most of the turbines are recycled or sold to wind farms in Asia or Africa, but recycling the blades presents technical challenges due to the use of composites, coatings, and other blended materials155 , with most ending up in landfills.
Cabling: Due to power losses, crushing failures, and connection degradation and dynamic loading issues, cabling is a major cost item. However, opportunities exist for designing overlapping solutions with oil and gas operations as explained in Section 3.3 - transmission, connection to the grid and to the platform. Alternatively, developments in floating and subsea substation design could pave the way for removing dynamic export cables connecting the substations to shore.
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
104 105
Floating offshore windFloating foundations: Displacements from waves, currents and strong winds present additional challenges for floating foundation designs, reducing performance and accelerating ageing. The main challenge is combining foundation stability with acceptable motion while keeping costs low156.
To keep foundations as stable as possible, there are numerous design variations for the four main types of wind installation: barge, spar, tension leg platform (TLP) and semi-submersible (a merger of spar and barge) (see figure 3.8). Design standardisation allows for production volumes to ramp up quickly using existing supply chains and manufacturing facilities. Floating turbines can be assembled onshore and towed to their final location at considerably lower cost.
Cabling is another important challenge. Conventional submarine cables secure the foundation to the seabed, yet floating components that are attached to the cables also move synchronously with the floating turbine. Exposure to the continuous bending and twisting forces from waves, currents and the floater increases the likelihood of mechanical damage. Dynamic cables with superior strength should be used so that cables can match the turbine’s service life158. Also, as capacity grows and the wind turbines share transmission systems, quick disconnects/reconnects are important to maintain uptime for the remaining turbines of the system when servicing one.
Floating and fixed-bottom installations can benefit from additional advances. Automated solutions for inspection and even installations will be increasingly important as wind installations move further offshore.
Figure 3.8: Floating offshore designs
Airborne windAirborne energy systems: Airborne energy systems have the potential to produce a lower LCOE159 due to requiring less material, meaning capital costs are lower, and the ability to produce more energy than wind turbines. However, there are a number of issues with AES, including: low capacity factors, shorter lifespans, less reliability and impractical design160. If these significant challenges are overcome, AES could be deployed on the UKCS over the next three decades.
Table 3.8: Technology challenges of floating wind turbines
FLOATING WIND TURBINES INNOVATION GAP
Standardisationoffloatingfoundations: to enable mass-production
Mooring designs: to enable stability against harsh weather and sea conditions
Dynamic cabling: to withstand change of forces on the cables due to moving foundation
Sharedchallengeswithfixed-bottomwind: blade leading-edge erosion, magnetic gearing, acoustic emission condition monitoring, automated inspection shared by fixed-bottom structures
Table 3.9: Technology challenges of AES
AIRBORNE ENERGY SYSTEMS (AES) INNOVATION GAP
Energy generation mechanism: feasible, efficient harvesting of wind energy
Kite and drone design: efficient, reliable, and durable designs with a possibility to standardise
Tethering systems: durable tethers
Motion control algorithms: machine learning for flight path optimisation
Critical gap, unlikely to be resolved without strong effort Needs additional effort On track to be resolved
Barge Semi-submersible Spar Tension-Leg Platform
Source: Wood Mackenzie
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
106 107
Other renewablesMarine energy
Current status
Tidal and wave energy are the are two most common forms of marine energy. The UKCS has the potential to be a hotspot for marine energy due to predictable wave patterns. Moreover, marine energy could be coupled with wind to balance power output. For example, novel engineering approaches like “Wind for Water injection (WINWIN) from DNV GL161 could help build momentum for both floating wind and tidal development at scale by improving operating and power output efficiencies. However, installations to date have seen limited success and a wide variety of designs are still in development and testing (see figure 3.9). Startups like Ocean Power Technologies and Carnegie Clean Energy have made slow progress, while others like Pelamis have gone bankrupt162. The European Marine Energy Centre, based on the Orkney Islands163,
Floating solarThis involves placing solar PV panels on floating supports. Challenges with floating solar include electrical safety and mooring issues176 in harsh sea conditions and limited irradiation potential of the UKCS, while other, more attractive renewable energies are easily available. For those reasons, floating solar is unlikely to contribute significantly to the UKCS’ renewable energy generation targets. However, speculative offshore renewables such as floating solar could offer additional flexibility to the future grid and to mitigate the risks associated with relying only on hydrocarbons and wind.
Table 3.10: Technology challenges of marine energy
MARINE ENERGY INNOVATION GAP
Power take off: economically feasible energy harvesting mechanism of tidal or wave
Fouling: antifouling coatings for durability
Stable foundation and support systems: durable position maintenance in harsh environmental conditions
Exploration of marine potential: systematic data collection and analysis of the total and feasible potential
Table 3.11: Technology challenges of floating solar
FLOATING SOLAR INNOVATION GAP
Wave tolerance: improving the current 1m-2m wave tolerance to withstand UKCS conditions
Waterclogging: pumping mechanisms to keep the system afloat
Clouding: coatings or automated cleaning against precipitation on the panels decreasing efficiency
Durable photovoltaic panels in seawater conditions: resistance to fouling and saltwater spray
Critical gap, unlikely to be resolved without strong effort Needs additional effort On track to be resolved
Figure 3.9: Tidal systems168
has been at the centre of major developments. The most advanced project is Simec Atlantis Energy’s MeyGen pilot in the Orkney waters164, which exported 13.8 GWh of electricity to the grid in 2019165 and has plans for two more turbines and an improved grid connection in 2020166,167.
Technology challenges, accelerators & enablers
Marine energy’s high upfront costs, suboptimal durability in subsea environments and maintenance challenges hamper economic feasibility. The costs and performance of basic components need to be addressed including:1. the structure and moving components that
capture energy;2. the mooring to keep these systems in place;3. the power take-off systems converting
movement to electricity, and;4. control systems to safeguard and
optimise performance under various operating conditions.
Floating foundations for tidal systems, such as the barge-mounted models from companies like Magallanes Renovables169 and Orbital Marine Power170, aim to ease manufacturing, installation and maintenance by removing any construction on the sea floor. The sector has not yet reached consensus on a winning design for wave systems – although there are a wide range of options that harness wave power under different conditions and in different places.
Other major barriers to development are site selection and equipment maintenance. Improved data on wave and tidal potential around the UK is needed to improve location selection171. Additionally, solutions such as high durability antifouling coatings172,173,174 or approaches to automatically remove fouling175, are needed to improve equipment maintenance.
Tidal turbine
Sea level
Current
Seabed
Source: Wood Mackenzie
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
108 109
Transmission, connection to the grid and to the platformCurrent status
Today most offshore wind farms are relatively close to shore (<50 km) and are connected to the grid by an AC cable. Offshore substations balance the load177. (see figure 3.10). Installations further from shore require other technologies. Germany’s latest offshore connection (Borwin 3) at ~160 km from shore uses high voltage direct current (HVDC) converter platforms and cables178.
Figure 3.10: Connecting to the grid179
Source: Adapted from EnBW
Undersea Cable: Transmits the electricity from the wind farm to the shore.
Offshore Substation: Increases the voltage of the electricity generated by the turbine to transmit power more efficiently.
Nacelle: Houses the generator and gear box, which convert rotor movements into electricity.
Blades: Catch wind and create movement.
Transition Piece: Connects the turbine tower and foundation.
Monopile Foundation: Fixes the turbine to the sea bed.
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
110 111
Technology challenges, accelerators & enablers
Offshore transmission systems typically face harsh environmental conditions: mechanical loading due to marine currents and the movement of waves, temperature extremes, excessive humidity and salt pollution. Mature cabling technologies for interconnectors between substations and shore connections can manage these conditions. However, lighter and more durable materials make significant improvements.
For instance, cables with cross-linked polyethylene (XLPE) insulation are light and allow ships to transport longer sections of it. That means fewer cable joints are required, which decreases installation costs180. Improved insulation can also reduce transmission losses and allow for smaller cable sizes. Furthermore, opportunities for co-development and implementation exist with the oil and gas sector given the initiatives for platform electrification.
Floating substations can also reduce costs and bring flexibility to offshore power systems, though they require extra cabling due to their mooring systems (see figure 3.11). Subsea stations that integrate multiple elements such as electricity transmission, platform electrification and energy storage could enable shared capex between multiple stakeholders. Siemens and ABB181 are exploring a distributed asset setup like this (see figure 3.12).
Table 3.12: Technology challenges of transmission systems
TRANSMISSION SYSTEMS INNOVATION GAP
Light, durable coatings: to cut transportation and installation costs
Cable inner design: placement of cable elements for electrical stability and improved transmission speed
Floating substations mooring: to resolve issues around cabling and stability to reduce costs
Critical gap, unlikely to be resolved without strong effort Needs additional effort On track to be resolved
Figure 3.11: Floating substations184
Figure 3.12: Subsea substation concept
Source: Adapted from Viscas
Source: Adapted from Riveramm
Geothermal For many years, geothermal energy on the UKCS has been discussed as another potential renewable resource, especially for baseload electricity supply. Historically, offshore exploitation of geothermal resources has been considered economically unfeasible, but recent advances in offshore technologies like drilling and power generation, rising interest in repurposing ageing infrastructure, and the increasing urgency of decarbonisation have revived interest in the idea186. The concept has yet to be proven offshore, and geothermal leaders like Iceland are only beginning to explore the resource potential in 2020187. Lengthy development timelines, high capital costs, unclear ownership structures, and uncertainties around the technologies result in slow momentum for offshore geothermal on the UKCS. With ample availability of more accessible renewable resources, geothermal will likely be at most a minor contributor to the 2050 energy mix.
Shore switching station & Shore system grid transmission line Floating substation
(66/22 kV substaion/observation tower)
2 MW windmill & semi-submersible floating structure
22 kV riser cable
Intermediate buoy
Intermediate buoy
Intermediate buoy
66 kV riser cable
66 kV submarine cable
Sea-bed splice
Subsea power stations: In 2019, ABB announced the world’s first subsea
power distribution and conversion system after completion of a 3,000 hour shallow
water test together with Equinor, Total and Chevron182. Siemens is also at the final stages of commercialising its unit after testing in shallow Norwegian waters in November 2018183. As the
concept of subsea factories develops in the offshore sector, subsea power stations will be
vital in supplying the required electricity.
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
112 113
Energy storage Current status
The intermittent and variable nature of renewables means that the gap between power supply and demand needs to be bridged. Currently, renewable energy generation does not yet exceed demand at any instant188. As offshore renewable capacity grows and becomes a larger component of the UK baseload power supply, it will be increasingly challenging to fully utilise generation capacity and maintain enough reserves for peak demand without sufficient system flexibility. Energy storage capacity and other mechanisms will be key to reducing the costs of integrating variable renewable energy.
System flexibility can currently be managed in several ways: gas peaker plants, pumped-hydro, demand-response programmes and interconnectors all provide options. As renewables penetration increases, energy storage will be required to manage both short- and long- term needs. Battery systems can store power for seconds to hours for continuous, stable power supply and also improve grid stability. Deployment of grid storage solutions is at an early stage. Nearly 1 GW of battery devices are currently used across the UK189. Seasonal storage is not yet possible using batteries and other solutions, such as long-term hydrogen storage, will need to be developed instead.
Technology challenges, accelerators & enablers
Wind power’s variability means that there is a need for 10 MW-100 MW batteries with shorter discharge durations (seconds to minutes) and energy storage in the minutes to hours (MWh to GWh) range to counter cannibalisation of power prices, the depressive influence on the wholesale electricity price at times of high renewable output190 (see figure 3.13). Producers are addressing technology challenges, by
commercialising new electrode materials, improving battery cell packaging and including battery management systems to improve capacity, safety and cycle life.
Buoyed by the uptick in electric vehicles, lithium ion (li-ion) batteries have reduced in price and manufacturing has scaled up, making these the preferred energy storage option. Li-ion batteries primarily differ by cathode chemistry: each has its own benefits and drawbacks. The long lifespan, high safety and relatively low price point of lithium iron phosphate (LFP) make it an attractive option. However, improvements in the nickel manganese cobalt oxide (NMC) li-ion batteries and scale up in production has sufficiently lowered its costs. NMC batteries are a viable and more energy dense option for electric vehicles. Besides li-ion, flow batteries such as vanadium redox or zinc bromine are increasingly used in large power storage applications.
An important use case for batteries offshore is reducing the need for spinning reserves, i.e. keeping multiple gas turbines running for redundancy. 30 minutes on battery power is enough to start a backup gas turbine, thus avoiding the substantial emissions from spinning reserves. In addition, energy storage is vital onshore to ensure power coming from the UKCS can be reliably integrated with the national grid. For example, the Batwind project, announced by Equinor and Masdar, connects the 30 MW Hywind farm to an onshore battery storage farm. Offshore storage will eventually be required as the offshore grid develops. It will be more economical to have storage closer to generation and offshore consumption to minimize the losses through cabling mentioned in Section 3.3 - Fixed-bottom offshore wind. Offshore storage demand could potentially be met through hydrogen. The development of seasonal storage options for offshore renewables is likely to rely on large-scale onshore storage options - such as the recent liquid air battery pilot in Manchester405 - and on development of power conversion and storage technologies like green hydrogen (as discussed in the hydrogen section).
Figure 3.13: Energy storage technologies: discharge time vs power rating
Box 3.1: Use cases for energy storage offshore
Lithium ion Battery
Hydrogen fuel cells
Electrical ThermalHydrogen-related Mechanical Electrochemical
1KW 10KW 100KW 1MW 10MW 100MW 1GW
System Power Rating, Module size
Disc
harg
e tim
e at
rate
d po
wer
seco
nds
min
utes
hour
sda
ys
High-power supercapacitors Super conducting magnetic
Flywheels
Nickel metal hydride battery
Nickel cadmium battery
Advanced lead acid battery
High energy supercapacitors
Cryogenic energy storage
Sodium sulphur
Flow battery
Pumped hydro
Compressed air energy storage
Electrification of oil and gas platforms:
• Transocean’s Spitsbergen semi-submersible has a hybrid energy storage solution, developed in partnership with Aspin Kemp and Associates, which captures waste energy during normal rig operations and uses it to power the rig’s thrusters192.
• Siemens BlueVault li-ion battery system will be first deployed on Northern Drilling’s West Mira drilling rig in the North Sea as part of a hybrid diesel-electric power plant193. It has four converter-battery systems for a maximum of 6 MW output during peak load times or as backup. It will reduce CO2 emissions by 12%194.
Source: Fluenceenergy.com
Lead acid battery
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
114 115
Renewable energy ecosystem and path to 2050 Each of the offshore renewable power systems will have their own ecosystem and will progress at a different pace over the next 30 years.Fixed-bottom wind will remain the dominant option, with growth largely coming from incremental improvements such as further blade length increases195. Average turbines are around 9 MW today and expected to increase to between 12 and 15 MW by 2030 and over 20 MW by 205020 (see figure 3.14).
Floating wind can expand the UKCS’ potential for energy generation. It would tap into stronger winds in areas with depths or seafloor compositions that are unsuited for bottom fixed wind. It could also provide flexibility, as turbines could potentially be relocated. Further commercialisation of floating windfarms could result in a ~60% decline in LCOE by 2040, which would make the cost comparable to fixed-bottom wind turbines20. Government funded collaborations include the EU’s Corewind project196, which targets cost reductions for mooring systems, cabling and foundation stability, for example. Still, further cost reductions will require significant investments and policy backing. Areas that need improvement are support vessels and infrastructure - large port areas for production lines, component set down and wet storage of assembled units197,7.
The levelised cost of electricity (LCOE) of airborne wind systems is currently multiple times higher than that of bottom- fixed wind. Some optimistic scenarios expect steep cost declines from improvements to the technology, such as lower material use. With those improvements, commercialisation could be expected around 2035. However, AES would first need to overcome considerable technology challenges, such as durability, to match the lifetime of existing wind turbines198,20. It’s an unlikely choice for the UKCS in the near- and mid-terms.
Marine energy, given its high predictability, could provide stable baseload power. However, funding is limited, and the technology is not yet practical or economical. Its potential by 2050 also remains uncertain. If ongoing pilots like Meygen and CapeSharp Tidal provide promising results, that could merit further government funding.
By 2050, offshore wind farms and other renewable technologies will be increasingly further away from shore. More HVDC cables and more offshore substations will be needed to bring costs down. A 2016 National Renewable Energy Laboratory (NREL)199 study found that when transmitting electricity at high voltages over 220 kV, HVDC cables are most cost effective for transmission distances over 110 km. Most projects operating or planned for the next decade are closer to shore and would use HVAC. An HVDC network would mostly benefit interconnectors for international energy trade. After 2030, as floating wind farms become more common, HVDC cables will become more important to effectively integrate different systems.
As the offshore renewable energy ecosystem grows, several other challenges need to be addressed: Grid integration and offshore storage: Renewables will be a large component of a net zero UKCS, eventually supplying power to the UK and to the UKCS itself. Wind’s intermittent nature will make it highly challenging to maintain power reliability and quality while it feeds into both the complex offshore grid and the UK’s already strained transmission and distribution grid. Therefore, analytics that predict generation and energy storage capacity onshore and ultimately offshore will be critical. Adding storage capacity requires a business model built on a suitable regulatory framework and commercial infrastructure. Adding storage to a grid is complex from an ownership and operational perspective, as the assets both generate and consume, or store, power. In the mid to long term, these complications could be exacerbated as the offshore portion of the grid expands and international connections and energy hubs become more common. When that happens, offshore storage will be required closer to points of use. Flexibility around operational regulations will be critical to securing maximum economic value from the integrated energy system.
Resolving policy and ownership issues: A hub-spoke setup is one of several connection options. This model can connect multiple generation assets to shared central substations and transmission cables to meet demand from various sources: the UK, electrified platforms or interconnectors. The setup has value for governments and energy operators alike but raises issues of ownership and maintenance as the assets are shared. While there is no one size fits all solution to managing offshore assets, transmission system operators are in a position to improve coordination and standardisation of projects. As the energy ecosystem integrates and becomes more complex, system operators need to collectively determine and adopt best practice.
Figure 3.14: Forecasted growth in turbine ratings
Source: Wood Mackenzie
20
2
4
6
8
10
12
14
16
18
2015
Global average
2016 2017 2018 2019e 2020e 2021e 2022e 2024e 2025e 2026e 2027e 2028e
Germany Taiwan UK US China
181%
Ave
rage
Rat
ings
(MW
)
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
117116
Speculative technologies for renewable energyOffshore compressed air storage
• Uses offshore pressure vessels to compress air: startup company FLASC’s hydraulic solution displaces a column of seawater with air200. Startup Hydrostor compresses air in underwater balloons201.
• Can provide energy storage for small clusters or single turbines to level out power generation and transmission peaks and reduce cable costs.
Offshore pumped hydro energy storage
• Fraunhofer’s StEnSEA project (Stored Energy in the Sea) fills or drains subsea concrete spheres with seawater to store energy.
• The project identified potential sites with a cumulative storage capacity of around 817 terawatt-hours202.
Self-assembling large-scale offshore wind turbines
• The EU ELISA project demonstrated a 5 MW fixed-bottom turbine, constructed as base, tower and turbine modules at an inshore wet yard. Tugboats tow the modules to the offshore location, where the base is ballasted and conventional heavy-lift jacks raise the telescoping tower section-by-section.
• There is only a handful of offshore heavy-lift cranes globally that can construct large turbines. Self-assembly avoids the necessity and high costs of these cranes203.
Optimisation of operations and maintenance: Offshore wind farm operations and maintenance are becoming more industrialised as providers consolidate, which has increased scale as services are bundled together. Further improvements in operations and maintenance will help decrease costs and improve reliability and output.
Life extension and decommissioning: Many of the turbines currently operating or installed in the next few years will require life extension or decommissioning by 2050. The impact of this must be analysed now. Studies need to weigh up whether and how to remove substructures in the seabed. They should consider benefits such as economic value of recovered materials against costs, including damage to marine life that will be caused by recovery operations. The lifetime of the turbine has already increased from 20 years to almost 30 years. That will continue to improve as technology evolves. How often turbines are decommissioned will change as their lifespans increase, while development of floating wind will reduce much of the decommissioning efforts related to turbine removal.
The development of grid management systems and onshore energy storage will need to keep pace with growing offshore energy capacity and intensifying decarbonisation efforts to prevent bottlenecking power delivery. In the long term, robust power management systems will become a crucial component to regulate the offshore grid. The emergence of energy hubs that connect multiple assets such as wind farms, oil and gas platforms, interconnectors and hydrogen production and storage will make that especially important. The UKCS’ role in energy supply and international trade will continue to grow for the UK as systems like this are set up.
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
118 119
2020 2035 2050
Renewable technology roadmap
Short-term Mid-term Long-term
Floating foundations becoming commercial
Automated inspection of blades with unmanned aerial vehicles
Ecosystem
• Fixed-bottom wind dominate the renewable offshore energy scene, growing in capacity due to larger blades, taller towers, and bigger turbines.
• Onshore energy storage capacity grows to integrate growing UKCS generation capacity into the national grid.
• Automated inspection and maintenance with aerial drones emerge to reduce operating costs.
• Commercial scale floating wind farms start to emerge, with optionally HVDC-transmission systems to connect these to shore or with electrified platforms.
Ecosystem
• As dominance of fixed-bottom wind continues and floating wind grows, demonstration projects for aerial energy systems (AES) join the scenery.
• Early commercial-scale installations of marine energy can start to emerge.
• Increasing the number of energy generation assets offshore enables the development of offshore micro grids or energy hubs, which can be linked to energy storage and electrified platforms. Shorter wind farm development timelines are needed to align with oil and gas platform electrification timelines.
Ecosystem
• Provided pilots are successful, AES technology can be coupled to existing wind farms to increase capacity factors, while wind farm foundations provide opportunities to couple marine energy systems
• The offshore energy grid increases in complexity, with multi-directional power flow in a transmission network connecting platforms, energy hubs, storage assets, and interconnects, creating an interconnected system enabling flexible energy management and exchange.
Wind
Other renewables (marine)
Transmission systems
Energy storage
Critical path
Unmanned installation: remote onshore control of transporting and installing wind turbines
Successful AES pilots opening the path for utility scale implementation AES at utility scale
Wind turbine decommissioning
Marine energy
Transmission systems HVDC cables connecting floating wind farms to the shore
Hub-spoke models connecting wind farms to each other and to oil and gas platforms
Micro grids with offshore energy storage
“incremental gain” tech challenges that will get resolved with or without
dedicated effort
Parking lot
Larger turbines with fixed-bottom structures
HVDC cable design with novel coatings
Advanced battery chemistries for long-
duration large-capacity stationary storage
Figure 3.15
Source: Wood Mackenzie, Lux Research
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
120 121
HYDROGEN Over the last 20 years, hydrogen has been hailed on various occasions as the next big thing in the energy industry. But now, the hype has been backed by investment. Large government initiatives and sizeable investments from major corporates have created new momentum for hydrogen and it looks set to play a more prominent role in the future energy mix204.
3.4:
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
123122
Table 3.13: Reasons for hydrogen
Box 3.2: Key projects for low-carbon hydrogen production
Hydrogen is also being promoted as key to the UK’s future energy system. As noted in Section 2 - Sizing up the UKCS on the Road to Net Zero - of this report, by 2050 the CCC forecasts that the UK’s annual demand for hydrogen will be 270 TWh, to be used for industrial and domestic heating, energy storage, fuel and chemical feedstock210.
The UKCS can play a central role in supporting a future hydrogen economy. Besides decarbonising some of its own operations through the use of hydrogen, the UKCS has natural gas resources and vital CO2 storage capacity for blue hydrogen, strong offshore wind build-out to produce low-cost electricity in the longer term for green hydrogen, and possibilities for large capacity hydrogen storage. Hydrogen technologies also follow the traditional up-, mid- and downstream oil and gas value chain – production (as blue or green hydrogen), storage and transportation and hydrogen use – making the oil and gas industry a natural partner in building a future hydrogen economy.
The UKCS can play a central role in supporting a future hydrogen economy
Key projects for low-carbon hydrogen production:
• BP is partnered with Nouryon and Port of Rotterdam to study the feasibility of a 250 MW electrolyser supplying BP’s refinery206
• Neptune Energy and its partners PosHYdon234 project explores electrolysis on an offshore platform off the Dutch coast.
• Shell is studying the feasibility of linking 3 GW to 4 GW of offshore wind to electrolysers in the north of the Netherlands207.
• Japan is piloting hydrogen supply chain projects, shipping blue hydrogen from Brunei using liquid organic hydrogen carriers and from Australia using a dedicated liquid hydrogen transport ship208,209.
H2
The IEA believes there are four reasons why hydrogen is more likely to succeed this time205
1 It’s one of the few options for hard-to-abate sectors, like high-temperature industrial heat
2It contributes to policy objectives beyond renewable energy, like energy security, clean air, and economic development
3It can be a long-duration energy storage medium, critical to maintain the rapid growth of renewable electricity generation
4Legislative experience bringing other clean energy technologies, such as wind and solar, to scale can aid in successful commercialisation
Source: IEA
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
124 125
Hydrogen productionBlue hydrogen Producing energy or chemicals from hydrogen generates no direct carbon emissions, but hydrogen’s carbon neutrality depends entirely on how it is produced. Methane reforming is the primary hydrogen production process, mostly commonly steam methane reforming (SMR). The process involves the mixing of methane - usually from natural gas - with steam over a catalyst at temperatures of 800°C – 900°C which produces synthesis gas (syngas), a mix of hydrogen and carbon monoxide211. A water-gas shift reactor can convert the carbon monoxide, plus water, to more hydrogen, plus CO2. This process produces so-called grey hydrogen. It emits around 8 kg – 10 kg CO2 for each kg of hydrogen and costs approximately £1.40/kg of hydrogen depending on the local gas prices. Using carbon capture technology in this process yields blue hydrogen and adds around £0.9/kg to the costs212,213,214,215,216.
Current status
Less than 1% of global hydrogen production is currently blue7. Blue hydrogen is not fully carbon-neutral: CO2 capture efficiencies217 reach 85% – 95% at best, and current CCS flagship projects are closer to 30%13. However, it does not require new technology inventions, as blue hydrogen can combine existing methane reforming processes with CO2 capture equipment, which is well understood. Current blue hydrogen projects under development are typically linked to existing infrastructure in coastal petrochemical clusters, where they can benefit from natural gas supply as well as CO2 storage options offshore.
Table 3.14: Novel blue hydrogen concepts
Technology challenges
Like most thermochemical processes, both methane reforming and CCUS are more economical at large scales. High construction costs and space constraints make these technologies a poor fit for offshore operations, so nearly all projects are onshore. However, several organisations10,219,220 are developing methods to increase the efficiency of reforming and CO2 capture and decrease system footprints so that these technologies can be considered for use offshore.
Incremental improvements to SMR units have been in development221,8 for well over a decade and are readily available20,222 These incremental innovations can benefit both grey hydrogen production process as well as blue hydrogen. These improvements include better heat transfer and recovery and a reduction in the amount of catalyst materials needed23.
Alternative reforming technologies for blue hydrogen production can increase hydrogen yields and CO2 capture ratios while reducing the system footprint, making them relevant for the UKCS. Beyond novel concepts involving the use of sorbents or membranes to increase hydrogen
yields, alternatives to SMR are increasing in relevance too. Though autothermal reforming (ATR) has been commercial for decades in applications such as ammonia or methanol synthesis, it is now seeing renewed industry interest. ATR uses oxygen and steam in a single exothermic reaction with methane to form syngas. Compared to SMR it results in a higher concentration and purer form of CO2, reducing capital costs and allowing increased efficiency of the carbon capture equipment. Other reforming technologies being researched include plasma-based processes that yield hydrogen and carbon black. Despite the lower footprint of plasma reformers, and no catalyst requirements, chemical selectivity and energy requirement remain a challenge for these technologies223.
Key projects for blue hydrogen production:
• Examples of blue hydrogen projects under development are the UK’s Acorn and HyNet projects218 and the Dutch H-Vision Initiative and Hydrogen to Magnum (H2M) projects13.
H2
• Membrane removes hydrogen from reforming reaction, shifting reaction balance to higher hydrogen yields at lower temperatures
• CO2 is concentrated in exhaust as high as 90%, facilitating downstream CO2 capture
• Key challenge: thinnest possible, yet durable membrane to increase efficiency10,224
• Calcium oxide or other CO2 sorbent removes CO2 from reaction, shifting balance to higher hydrogen content in exhaust (>90%) at lower temperatures
• Sorbents are separated from gas stream to de- sorb CO2. While an energy-intensive process, the released CO2 is suited for storage without further purification225
Natural gas
Steam
Hydrogen
H2
CO2-enriched exhaust
400
°C –
500
°C
Flui
dize
d be
d re
acto
r
H2
H2
H2
H2
H2
H2
H2
Natural gas
Steam
CO2-depletedsorbent
Fluidized bed reactor
CO2
CO2-enriched sorbent
H2-enriched exhaust
400
°C –
500
°C
Rege
nera
tor
Natural gas
Steam
Hydrogen
H2
CO2-enriched exhaust
400
°C –
500
°C
Flui
dize
d be
d re
acto
r
H2
H2
H2
H2
H2
H2
H2
Natural gas
Steam
CO2-depletedsorbent
Fluidized bed reactor
CO2
CO2-enriched sorbent
H2-enriched exhaust
400
°C –
500
°C
Rege
nera
tor
Figure 3.16: Schematic of the sorbent-enhanced reformer to be used in the HyPER project
Transport Calciner and Firebox
H2 Product Gas Discharge
CO2 Product Filter
Gas-Solid Eductor #2
Bubbling Fluidized Bed
Gas-Solid Eductor #1
De-pressurizing Lockhopper
Freeboard
H2 Product Filter/ Sorbent Standpipe
Sorbent Fill Port
Source: HyPER project
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
126 127
Green hydrogen Green hydrogen is produced using one of several types of electrolysers227,228. The process uses renewable electricity to split water molecules into hydrogen and oxygen.
Current electrolysis methods are just under 70% efficient. Green hydrogen economics are almost exclusively determined by a system’s power prices, load factor and capital costs7. It is possible to place electrolysers onshore and offshore. Though offshore adds the challenge of space constraints and operational costs, it also provides a path to market for excess wind power that would otherwise be curtailed.
Current status
A recent study7 found the UK has strong prospects for low cost green hydrogen because of its wind power potential. Globally, several onshore electrolyser projects linked to offshore wind farms have been announced. In industrial settings, electrolyser technology is approaching maximum efficiency, but design improvements can still achieve incremental efficiency gains.
As they are able to maintain high efficiency even while power input fluctuates, PEM electrolysers are a more attractive option to be used with large scale renewable power from the UKCS. They can ramp up and down within seconds; a typical alkaline electrolyser needs minutes. They can also exceed their maximum capacity up to 200% for a few minutes while still running efficiently at lower capacity, maximise the usage of fluctuating renewable electricity13.
Electrolyser projects onshore are most economical for electricity that is produced near to shore. Offshore electrolysis is in its infancy and would require desalination systems, but the technology could be used on repurposed or new platforms, in wind turbine foundations and subsea locations. Producing hydrogen offshore has the benefit of making more efficient use of electricity that is already produced offshore and could provide an accessible and low-carbon alternative fuel to be used on oil and gas platforms.
Table 3.15: Main hydrogen electrolyser types
Table 3.16: Offshore green hydrogen concepts
Alkaline (AE) Proton exchange membrane (PEM)
Solid oxide electrolysis cell (SOEC)
Benefits
• Lower costs – cheaper catalyst metals
• Long performance history
• Rapid response time, better suited to pair with intermittent energy sources
• Operates at high current density and wide load range
• Operates at very high temperature (>700 °C) and efficiency
Drawbacks
• Liquid electrolyte is hazardous, corrosive, and susceptible to leakage
• Requires several minutes to ramp up and down
• Higher capex• Reliance on rare or
costly electrocatalyst materials
• Moderate time to ramp up or down
• Not suited for intermittent use because of need for high heat
• Unproven in commercial use
Electrolyser system examples: • In 2018, ThyssenKrupp229 piloted a commercial scale system with a very high efficiency of 82%, which it
accomplished by virtually eliminating the gap between the electrodes and membrane in a so called zero-gap configuration alkaline electrolyser.
• Electrolyser footprint is a crucial constraint for offshore green hydrogen production on the UKCS. For instance, ITM Power’s 2 MW (800 kg hydrogen per day) electrolyser system and auxiliary systems fits in two 40-foot ISO containers230, minus desalination. Such sizes allow an offshore platform to produce 3 tonnes to 15 tonnes green hydrogen per day, depending on platform size231. Based on current infrastructure and proposed systems that repurpose decommissioned platforms, commercial offshore hydrogen production makes the most sense linked with far from shore wind farms, where high costs and energy losses of power cables favour use of a hydrogen pipeline network to demand centres in the UK or UKCS232,233.
H2
CONCEPT DESCRIPTION
1 The Dutch PosHYdon234 project aims to install a containerised desalination and electrolyser system on the Neptune’s Q13a-A platform and power it with offshore wind.
2Ørsted and ITM Power are exploring a novel concept, placing the electrolyser in or near a wind turbine tower with a direct DC cable connection to minimise power losses. A central substation platform then supplies a network of such electrolysers with desalinated water and power flow control via umbilicals, while housing the compressor station to pump produced hydrogen into a transmission pipeline .
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
128 129
Technology challenges
The high capital cost of electrolysers - currently between £640 and £720/kW - is a major obstacle. The cost can be offset by making optimal use of lower power prices through operational improvements, consistent power supply, and use of digital grid control software. Costs are high because electrolyser stack assembly is a largely manual process done in small factories. Scale-up236 and automation methods such as roll-to-roll manufacturing could reduce costs by 30% or more by 2030237.Making these improvements is a major focus for leading producers like ITM Power, NEL, or Siemens. These advances could reduce capex to between £160 and £240/kW after 2040238, though some Chinese manufacturers claim it is possible to achieve those costs now. The solar PV and battery industries have demonstrated that this can be done: costs for both have plummeted rapidly with massive scale-up of production.
Table 3.17: Technology challenges of hydrogen production
BLUE HYDROGEN INNOVATION GAP
High-efficiencyreformers: minimal footprint, efficient reformers with carbon capture for blue hydrogen
Hydrogen membranes:thin, high-flux, durable membrane to separate blue hydrogen in reformer
CO2 sorbents: high-capacity sorbents that are more durable at high temperatures, have the lowest possible energy requirements for efficient regeneration and release CO2 in blue hydrogen production
GREEN HYDROGEN INNOVATION GAP
Electrolyser manufacturing: economies of scale and production automation in factories
Electrolyser catalyst: low-cost, high current density, and durable catalyst materials
Saltwater electrolysis: cost-effective integrated desalination or direct seawater electrolysis to prevent corrosion or formation of chlorine gas in seawater electrolysis
Subsea electrolysers: systems suited for autonomous, flexible hydrogen production and pipeline compression on the seafloor
Critical gap, unlikely to be resolved without strong effort Needs additional effort On track to be resolved
Figure 3.17: Electrolysis process
Cheaper electrode catalysts provide another opportunity to reduce costs. PEM electrolysers today use expensive but higher-performing platinum and iridium, but advances in achieving similar performance with lower-cost catalyst materials could reduce capital costs by 5% – 10%.
Using seawater for hydrogen production could become vital to hydrogen economies around the world. A 200 MW ATR can consume up to 30-40 m3/hr of water, a volume that would be difficult to source in nations where fresh water is scarce. However, offshore electrolysis has unique challenges as salts can cause corrosion and form chlorine and other toxic gases during the process239,240. PEM electrolysers typically require water treatment systems even with drinking-grade water supply; seawater would need membrane desalination technology241, which would significantly increase costs.
Technology developments for offshore electrolysis:• Saltwater desalination for green hydrogen costs is one of the key aspects being explored in the UK’s Project
Dolphyn242 for large-scale offshore hydrogen production. As an alternative to desalination, a few groups, including the University of Leiden45, Technical University of Berlin243and Stanford University44, are working on specialised catalysts that allow safe direct seawater electrolysis. As early stage research, these catalysts still need large improvements in lifetime, efficiency and costs before they can compete with desalination-coupled PEM electrolysers. The company sHYp, recently selected as part of the Cohort 3 of the OGTC’s TechX accelerator programme, is also working on producing green hydrogen from seawater without the need for desalination244.
• Since space is scarce offshore, participants in the U.S. DOE H2@Scale program are developing subsea electrolyser systems that can be placed below floating wind farms, linked to power supply and a hydrogen export pipeline. While that will require further development of subsea desalination and compact electrolyser systems, the added benefit is that the water pressure can help produce hydrogen at high pressure for pipeline transport, without the need for mechanical compression.
H2
4H+ + 4e- 2H2Cathode Reaction
O2 + 4H+ + 4e- Anode Reaction
Hydrogen Bubbles
Oxygen Bubbles
Hydrogen Oxygen
2H2O
Mem
bran
e
Cathode Anode
Power Supply
- +
Source: Wood Mackenzie
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
130 131
Hydrogen storage and transport While hydrogen storage and transport has little direct carbon abatement potential, it is a crucial enabler for the hydrogen economy. The UKCS has an important potential role to provide storage capacity for blue or green hydrogen. In addition, the build-out of the necessary storage and transport infrastructure also benefits development of offshore green hydrogen production, which will require pipelines or shipping routes to bring hydrogen produced far from shore to demand centres247.
Hydrogen has the highest energy content per kilogram of any fuel yet as the lightest element in the universe, its volumetric energy density is very low: moving any meaningful amount of energy requires large volumes. This low volumetric density makes it impractical to compress and then to store or ship potentially hundreds of tonnes of hydrogen daily from the UKCS to the mainland without extensive multi-stage compression or another conversion to a denser form.
There are broadly four technology options to improve hydrogen transport economics and one large-volume storage option:
While different technologies have their own benefits and drawbacks, each approach adds between £1.6 to £4.8/kg to the hydrogen cost248, depending on distance and local energy costs. Upfront investments that can exceed £80 million per plant are required. Each approach can suffer conversion losses ranging from 10% to 45%43 of the energy contained in the hydrogen.
Pipelines
Current status
For pipeline transport, blending hydrogen with natural gas is currently possible7 to about 20% volume without considerable equipment modifications. The HyDeploy249 and H21 North projects in the north of England247 are trialling blended gas for domestic or industrial heating. However, as hydrogen demand grows, pure hydrogen supply chains will also become necessary. Dedicated hydrogen pipelines have been used onshore for decades. The HOP project229, coordinated by the OGTC, found in its
Storage & Transport
1 Compress the hydrogen up to 50 bar – 100 bar and transport by pipeline
2 Combustible carrier molecule: Convert the hydrogen to another energetic carrier molecule, such as ammonia, which can be directly combusted, or cracked to release the hydrogen again
3 Non-combustible carrier: Combine hydrogen with a reversible carrier molecule (liquid organic hydrogen carrier, LOHC). The hydrogen is released at the destination and the depleted carrier is reused
4 Liquify the hydrogen at –253 °C and store in well-insulated cryogenic tanks
Storage only
5 Store very large volumes of hydrogen under mild pressures in underground reservoirs, connected to a pipeline or a transport terminal
Table 3.18: Hydrogen transport and storage options
Figure 3.18: Compressed hydrogen volumetric density
preliminary results that 30% of the UKCS’ oil and gas pipeline infrastructure could potentially be used for hydrogen services (subject to further assessment), which could potentially offer considerable savings over new construction. Pipelines have the added benefit of line packing, offering hydrogen storage buffer capacity by modulating the pipeline pressures.
Technology challenges
A key technical challenge in pipeline repurposing is that hydrogen under pressure can diffuse into the pipeline materials, and make higher tensile strength steel brittle, or affect gaskets or soft seal materials, increasing the risk of leaks or bursts.Any repurposing requires careful evaluation of the pipeline materials and the condition of valves and other points where hydrogen could leak. For incompatible pipelines, it may be possible to install polymer liners, but this is technically challenging to do, even on land38. Furthermore, the lack of an odorant that can mix with hydrogen to make leaks easy to detect creates a safety risk.
5 kg hydrogen compressed to 700 bar, 500 km range
800 kg hydrogen compressed to 250 bar
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
132 133
Carrier molecules
Current status
Carrier molecules chemically bond to hydrogen, forming a liquid that can provide a high volumetric energy density while being easier to handle than gaseous hydrogen. Common options are reacting hydrogen with nitrogen to form ammonia or bonding it with organic molecules that can later release it again, dubbed liquid organic hydrogen carriers (LOHCs).
Japan has a strong focus on a hydrogen economy and is running a number of international hydrogen supply chain pilots using carrier molecules. Chiyoda, together with consortium partners, has started shipping hydrogen from Brunei5 to Japan using liquid organic hydrogen carriers250. Hydrogen infrastructure developer H2U will use ammonia to export hydrogen from South Australia’s Port Lincoln to Japan, as part of Japan’s Green Ammonia Consortium251. In the UK, Siemens and partners have constructed a green ammonia demonstrator to store hydrogen from an electrolyser powered by wind energy252.
Technology challenges
For both LOHCs and ammonia, energy conversion losses and transportation costs are comparable to liquid hydrogen, yet the technologies themselves face very different challenges.
Hydrogen carrier pilot projects: • Ammonia is produced with the Haber-Bosch process, reacting nitrogen and hydrogen over a catalyst at elevated
pressures and temperatures around 500°C. Pure anhydrous ammonia has nearly twice the energy density of liquid hydrogen, and while corrosive and toxic if released, it can be transported at mild pressure and moderate temperatures(<20 bar, -10 to -15°C). It can be burned in internal combustion engines or turbines, or used in specialised fuel cells. The Equinor supply vessel Viking Energy will be retrofitted with a 2 MW direct ammonia fuel cell for a first pilot by 2024253. Ammonia cracking to release hydrogen is less mature and requires improved catalysts to increase the energy efficiency at lower temperatures.
• LOHC are often derivatives of toluene, such as the methyl cyclohexane that is being used by Chiyoda. They are liquid and largely harmless at room temperature, making it possible to use existing bulk liquid tanks and ships. They release significant heat during hydrogenation, which is lost without waste heat recovery systems. In turn, they require sustained heating at temperatures of between 200°C and 350°C over one to two hours to release most of the hydrogen at destination. Some LOHCs require purification of the hydrogen to remove trace carrier molecules as well as hydrogenation byproducts such as CO2, CO, methane, and heavier cyclic hydrocarbons254.
H2
Liquid hydrogen
Current status
Hydrogen turns to liquid below –253 °C, making liquefaction an inherently energy-demandingprocess, but its high volumetric energy density means a standard shipping container can hold approximately 3,500 kg255. Hydrogen liquefaction is a well-established process in the industrial gas industry, but existing plants range from 5 to 35 tonnes of hydrogen per day, an order of magnitude smaller than what would be needed for large scale use of hydrogen energy256. The energy consumption of liquefaction processes is equivalent to 30 to 40% of the energy content of the hydrogen257, though better energy efficiency is possible258 at larger plants by minimising heat loss259. Liquid hydrogen can be used directly by fuel cells after it is warmed up to become a gas.
Technology challenges
While it’s possible to have small-scale liquefaction plants for the use of hydrogen offshore262,263, they will be less efficient than large-scale onshore ones. Shipping and storage require specialised cryogenically insulated storage tanks to minimise boil-off, which otherwise claims between 1% and 5% of the hydrogen over a few days. However, tankers and ships could capture boil-off and use it as fuel, while systems such as Linde’s LOPEX73 re-liquefier can turn 80% of the boil-off to liquid hydrogen again.
Underground and subsea storage
Current status
Underground reservoirs can store vast quantities of hydrogen in either salt caverns or depletednatural gas reservoirs. The technology to construct salt cavern for hydrogen storage is not widely used but it is relatively mature. Salt domes above and below the cavern provide a good seal. Two large
hydrogen storage caverns have been in operation near Houston, U.S264 for years and three small caverns have been in use up until recently near Teesside in the UK265.
Subsea hydrogen production and storage addresses the lack of space in topside platforms while enabling offshore operations. Currently, the DeepPurple project lead by TechnipFMC is the main project developing subsea hydrogen storage. While subsea storage presents materials challenges to the storage tanks related to the harsh environmental conditions, the technology to store hydrogen either in liquid or gaseous form remains unchanged.
Technology challenges
Offshore salt caverns have not yet been used for hydrogen storage, though the central North Sea basin does offer multiple potential salt cavern locations266. However, it is still unclear if depleted gas reservoirs are suitable, as hydrogen may escape through low porosity rock that is otherwise impermeable to natural gas. Also the hydrogen can react with the remaining hydrocarbons or sulphur compounds267, contaminating the hydrogen supply. The HyStorPor project conducted by the University of Edinburgh is currently studying the hydrogen reactivity with the rocks into which it is injected, the effectiveness of hydrogen migration through water-filled porous media, as well as the amount of hydrogen that can be recovered from the rocks268.
Liquid hydrogen supply chains: • Kawasaki Heavy Industries has built a
specialised ship to transport 1,250 m3 liquid hydrogen from Australia to Japan6, which was launched in December 2019 and will start trials in late 2020260. Similarly, in late 2019, BKK, Equinor, Air Liquide and partners received PILOT-E support to develop a liquid hydrogen supply chain for maritime applications in Norway261.
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
134 135
Figure 3.19: Offshore salt structures offer the UK possible salt cavern development options not found onshore
Table 3.19: Technology challenges of hydrogen storage and transportation
HYDROGEN STORAGE AND TRANSPORTATION INNOVATION GAP
Pipeline repurposing guidance: clear understanding of hydrogen’s impact on durability of repurposable UKCS pipelines
Pipeline re-lining: methods to refurbish or coat interior of pipelines to make them suited for hydrogen transport
Hydrogen leak detection: Odorant or other means to quickly detect potentially dangerous hydrogen leaks without sensors
Small-scale hydrogen liquefaction: small, modular, energy-efficient hydrogen liquefaction systems
Minimal boil-off storage: minimising or recovering boil-off losses from liquid hydrogen storage systems
Small-scale Haber-Bosch: scale-down of thermochemical ammonia production process without diminished efficiency
Ammonia cracking: energy-efficient ammonia cracking catalyst to obtain high-purity hydrogen at lower temperatures
LOHC catalysts: catalysts for low-temperature, fast, and complete dehydrogenation of liquid organic hydrogen carriers
Underground storage: comparison of hydrogen contamination risk in salt cavern vs. depleted oil / gas field storage
Critical gap, unlikely to be resolved without strong effort Needs additional effort On track to be resolved
Salt Structure - potential salt cavern option
Cenozoic Age (Paleogene) bedded salt deposit
Mesozoic Age bedded salt deposit
Paleozoic Age bedded salt deposit
Source: Adapted from: Caglayan et al. (2019)
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
136 137
Hydrogen turbines
Current status
Currently, platforms on the UKCS use wellhead gas in open cycle gas turbines269 to either generate power or mechanically drive compressors, using fuels like diesel as backup in case production is interrupted. These turbines are the biggest energy consumer on the UKCS. Many turbines can already run on hydrogen blends of between 5% and 95% hydrogen268. All major turbine producers, including Ansaldo271, GE82, MHPS272 and Siemens273 are developing turbines that are capable of running on 100% hydrogen, including duel-fuel designs81 that can use multiple fuels. Hydrogen’s high flammability can even increase combustion efficiency.
Technology challenges
Hydrogen’s low volumetric density and potential embrittlement of some metals mean that changes to ducting, seals, and valves are required, as well as possible retrofits for turbine blades so that they can withstand higher flame temperatures86,274. Changes in burner design may also be needed to avoid risks of damage because of hydrogen’s flammability and flame speed275,276 and its tendency to form nitrous oxide (NOx) at higher temperatures86.
Hydrogen use on the UKCSWhile the key demand drivers for the hydrogen economy are onshore9, there is also potential for hydrogen to help decarbonise oil and gas operations offshore using gas turbines or fuel cells. Fuel cell systems can be used for backup power, reducing emissions from gas turbines used as spinning reserves. A more challenging step would involve switching the primary fuel on the UKCS at the platforms from wellhead gas to low-carbon hydrogen. The platform would then depend on an external fuel supply, either via a hydrogen pipeline or storage that is either on deck or in barges. That would be most useful for platforms that can’t be reached economically by a direct power cable connection but can have a reliable hydrogen supply with ample redundancy.
Figure 3.20: Required modifications for hydrogen-fuelled turbines
Precise control of fuel/air mix to prevent high NOx emissions
Altered burner design to handle hydrogen’sfasterflamespeed
Air inletCompressor
Compressor turbine
Free (power) turbine Power shaft
Fuel inExhaust
Combustion chamber
Adjust tubing size and materials tohydrogen’shigherflowrates and potential steel embrittlement
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
139138
Even a relatively small 11 MW turbine that is running on pure hydrogen uses 1.1 tonnes of hydrogen per hour277, or one shipping container full of 500 bar compressed hydrogen every four to five hours. As a result, on the UKCS, hydrogen turbines would remain limited to use cases that require very high- power outputs, such as gas-to-wire applications that are linked to underground hydrogen storage or a hydrogen pipeline network.
Turbines fuelled by an ammonia-hydrogen blend are another alternative, as a blend of around 70% ammonia and 30% hydrogen approximates the combustion characteristics of natural gas278,279. The footprint and weight per kg of hydrogen of ammonia storage tanks are 10-fold lower than cryogenic hydrogen storage280, and ammonia blends also help to reduce turbine NOx emissions281. The key challenge is to demonstrate the technical and economic feasibility of using short platform shutdown periods to make the necessary modifications to older turbines. Setting up ammonia barge supply lines and demonstrating the feasibility and, given ammonia’s toxicity, safety of this solution are two additional challenges.
Hydrogen fuel cells
Current status
Avoiding a gas turbine altogether translates to fewer personnel, auxiliary facilities and reinforcement structures as well as improved safety282. When direct electrification is not possible, a hydrogen fuel cell power system can be an alternative. Fuel cells can have between 60% and 70% electrical efficiency, twice that of an open cycle gas turbine, are substantially less complex and operate reliably when combined with a battery system for peak power supply, without risks like flame-out283. Fuel cells have been backed by major governments like Japan, South Korea, the USA and Germany, developed by specialists like Plug Power, FuelCell Energy, Bloom Energy and Ballard Power Systems, and backed by the automotive sector and other major industries. In the U.K., Aberdeen
Technology accelerators, enablers and dependent technologies
Unlike hydrocarbons and renewable power, the use of hydrogen is still very small onshore and absent on the UKCS. The collaborative efforts needed to create this supply chain will be enormous. Three critical factors can enable the UKCS’ potential as a hydrogen supply and use hub.
1. The development of CO2 storage capacity will allow blue hydrogen production capacity onshore to grow to form a foundation for a renewable hydrogen ecosystem.
2. Cost-competitive production of green hydrogen, onshore or offshore, will require continued expansion and cost reductions of offshore renewable power.
3. Multi-billion pound investments will be needed to create supply chains for a hydrogen economy that are largely non-existent today.
The UK and regional governments can follow Japan’s example to promote hydrogen demand by supporting various demonstration projects. That would help to reduce uncertainty for companies and justify the large investments needed that are needed to create a low carbon, and eventually renewable, hydrogen supply chain.
Table 3.20: Technology challenges of hydrogen use
HYDROGEN TURBINES INNOVATION GAP
Hydrogen-combustors: burners and auxiliary systems to retrofit turbines to run on pure hydrogen
Ammonia-blend turbines: modify existing UKCS gas turbines to run on partially cracked ammonia, with safe ammonia storage on e.g. barges
FUEL CELLS INNOVATION GAP
Fuel cell manufacturing: economies of scale and production automation in factories to reduce capital costs
Fuel cells catalyst: low-cost, high current density, and durable catalyst materials
Critical gap, unlikely to be resolved without strong effort Needs additional effort On track to be resolved
City Council has the largest hydrogen powered bus fleet across Europe with 25 vehicles, with cities such as London and Birmingham planning to follow suit284. However, high capital costs have prevented widespread adoption in mainstream uses such as transportation and baseload power285. Fuel cells can also find application in the maritime sector, opening up the prospect of decarbonising the oil and gas supply chain. Currently, initiatives such as the HySeas project are testing the implementation of fuel cells in ferries, which can serve as a stepping-stone for the deployment of fuel cells in cargo ships286.
Technology challenges
Manufacturing automation and expensive catalyst materials are the main technology challenges for fuel cells. Like electrolysers, more output requires a larger electrode surface area, which limits the cost benefits of scaling up to larger devices. In the UKCS, fuel cells can be particularly attractive for smaller power loads, especially for applications where batteries are not the best solution38 – like subsea systems288. Fuel cells could also help to power floating small field production operations if equipped with sufficient fuel supply or a connection to nearby hydrogen pipelines.
Promoting hydrogen demand:• A consortium led by TechnipFMC287 has started
a study to grow hydrogen demand offshore, combining electrolysers powered by offshore wind with subsea storage and fuel cells to supply power to offshore platforms.
• Governments can also support demand by deploying hydrogen vehicles in public transport or other public services, such as the hydrogen buses serving the London area, or Alstom’s pilot for a hydrogen-fuelled train289. Another option is to subsidise the use of blue or green hydrogen in domestic and industrial heating, or as feedstock for the refining and chemical industry.
H2
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
140 141
Hydrogen ecosystem and path to 2050 An important first step for a hydrogen ecosystem centred on the UKCS will be detailed studies on the potential for savings from repurposing existing pipelines and platforms, and on hydrogen’s potential to decarbonise older assets. Decommissioning decisions can then be based on the assets’ utility for the full future energy system, not only hydrocarbon production290.
Production
Blue hydrogen production can form the foundations: it can be built with well-understood technologies at competitive cost of £2.3/kg of hydrogen43, in part because the UKCS can provide critical CO2 and hydrogen storage capacity. In contrast, costs of green hydrogen are between £3.2 and £4 per kg291, growing to as much as £5.6 to £6.4 per kg with desalination and electrolysis offshore38. As a result, blue hydrogen can be deployed earlier and faster in the UK. That will help to accelerate the development of critical hydrogen storage and transport technologies and build use case and demand for a UK hydrogen economy. Over time, natural gas prices and carbon taxes will tend to raise blue hydrogen costs, while green hydrogen costs will continue to fall as offshore renewable electricity costs drop and efficiencies help to improve larger-scale electrolysis projects. The first commercial deployments for green hydrogen may appear around 2030 and hydrogen production growth may tip in favour of green hydrogen around 204047.
Storage and transport
In a hydrogen economy, local conditions and policies will determine which value chain is best suited, and each option will have a commercial niche. Japan, with limited domestic energy resources, is setting up large-scale, long-distance pilot projects292 to supply hydrogen from Brunei or Australia. The opportunity for the UK lies in the strong potential for UKCS’ offshore wind build-out, CCUS capability and existing pipeline infrastructure. All of these should be leveraged to build a hydrogen economy. While the UK is exploring the potential to repurpose UKCS pipeline infrastructure for hydrogen transport, it is not yet emphasising alternative transportation methods. Those alternative methods could position it as a strong player in an intercontinental supply chain for hydrogen as a traded energy commodity.
Supply chain
By careful integration of widespread blue and green hydrogen production with underground storage potential, newly built or repurposed pipeline infrastructure and hydrogen shipping using ammonia, LOHCs, or liquid hydrogen, the UKCS will have an important role in enabling hydrogen use on the UK mainland and potentially other nations. Importantly, as offshore wind capacity grows, the role of hydrogen pipelines will grow as well; per unit of energy, a mile of (hydrogen) pipeline can be an order of magnitude cheaper than a power cable, making hydrogen a potentially more economic option to transport power from far from shore wind farms295.
From 2040 onwards, as green hydrogen builds on current pilots and learnings from rapid growth in onshore commercial electrolysis, commercial offshore green hydrogen projects that will have started to appear around 2030 can become cost-competitive with blue hydrogen. By 2050, blue hydrogen may still have double the production capacity of green hydrogen on the UKCS, but as reformer systems and gas fields near their end-of-life, these will increasingly be replaced by electrolysers towards a more renewable based energy system.
Table 3.21: Hydrogen transportation technologies
Ammonia LOHC Liquid hydrogen
Benefits
• Taps into existing supply chain
• Can be used as shipping fuel or combusted as ammonia-hydrogen blend in gas turbines with potentially minimal burner modifications
• Approx. twice the energy density of other carriers in anhydrous form
• Can be stored and transported in existing liquid bulk assets
• Safe to handle at room temperature
• Can remain liquid from production through to onboard tanks in commercial vehicles
• Easy to pressurise for compressed hydrogen tanks in passenger vehicles294
Drawbacks
• Anhydrous ammonia is corrosive and forms lethal gas clouds if released293
• Hydrogen cracking is immature and trace ammonia can damage hydrogen fuel cells, thus needing extensive purification or direct ammonia fuel cells
• Requires large conversion plants at supply and demand locations
• Dehydrogenation step is energy and time consuming
• Depleted carrier must be shipped back to hydrogen production site
• Hydrogen lost from boil- off is not consumed for several days
• Requires specialised, highly insulated tanks for storage and shipping
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
142 143
Speculative technologies for hydrogen
Photosynthetic hydrogen: direct solar water splitting
• Uses a nanostructured surface under sunlight to directly break down fresh or saltwater into hydrogen and oxygen.
• Can become a more efficient direct path to hydrogen instead of using renewable power and electrolysers.
Small-scale LOHC
• Chinese LOHC developer Hynertech aims to deploy small-scale catalytic units to dehydrogenate LOHC onboard fuel cell buses equipped with a two-tank system for loaded and depleted LOHC.
• While efficiency will be substantially lower than a large-volume dehydrogenation plant, onboard systems allow buses to run on hydrogen fuel that is safe and stable at room temperature in a standard liquid fuel tank.
Adsorption-based hydrogen storage
• Uses high-surface area materials, such as metal-organic-frameworks (MOF’s), to adsorb and release hydrogen from solid materials under controlled temperatures and pressure.
• Solid storage can have a volumetric energy density exceeding that of anhydrous ammonia, if it can overcome challenges with hydrogen losses, needs for extreme temperatures and pressures, high costs that increase in step with storage capacity, and high mass.
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
145144
2020 2035 2050
Hydrogen technology roadmap
Short-term Mid-term Long-term
Hydrogen membranes: thin, high-flux, and durable membrane to separate hydrogen in reformer
Saltwater electrolysis: cost-effective integrated desalination or direct seawater electrolysis to prevent corrosion or formation of chlorine gas in seawater electrolysis
Ecosystem
• Wide-scale adoption of hydrogen requires supply chains for large volumes. With no single clear winning technology, pilots using different options help identify economics and potential to repurpose existing UKCS assets.
• Low-carbon blue hydrogen is the lower-cost option in the near-term, but requires available carbon storage capacity to be achievable.
Ecosystem
• Besides hydrogen demand onshore, the UKCS could potentially use hydrogen, likely in the form of ammonia, for fuel switching of non-electrified platforms.
• With growing onshore demand, hydrogen storage will become critical, and together with potential far-from shore wind farms with electrolysers, can support the creation of a hydrogen pipeline infrastructure on the UKCS.
Ecosystem
• When wind farms develop further from shore, hydrogen can become an energy commodity produced both offshore and onshore in the UK, allowing the UK to potentially export energy in the form of hydrogen carriers or by pipeline.
• With growing hydrogen demand, blue hydrogen production will increasingly be decommissioned in favour of green hydrogen production.
Blue hydrogen
Green hydrogen
Hydrogen storage/transport
Hydrogen turbines
Critical path
CO2 sorbents: high-capacity sorbents that are durable at high temperatures, with minimal energy requirements for regeneration and CO2 release
Hydrogen membranes: thin, high-flux, and durable membrane to separate hydrogen in reformer
Subsea electrolysers: systems suited for autonomous, flexible hydrogen production and pipeline compression on the seafloor
Pipeline repurposing guidance: clear understanding of hydrogen’s impact on durability of repurposable UKCS pipelines
Pipeline re-lining: methods to refurbish or coat interior of pipelines to make them suited for hydrogen transport
Ammonia cracking: energy-efficient ammonia cracking catalyst to obtain high-purity hydrogen at lower temperatures
LOHC catalysts: catalysts for low-temperature, fast, and complete dehydrogenation of liquid organic hydrogen carriers
Ammonia-blend turbines: modify existing UKCS gas turbines to run on partially cracked ammonia, with safe ammonia storage on e.g. barges
Fuel cell manufacturing: economies of scale and production automation in factories to reduce capital costs
Small-scale liquefaction: small, modular, energy-efficient hydrogen liquefaction systems
Underground storage: comparison of hydrogen contamination risk in salt cavern vs. depleted oil / gas field storage
Fuel cells catalyst: low-cost, high current density, durable catalyst materials
“incremental gain” tech challenges that will get resolved with or without
dedicated effort
Parking lot
Small-scale reformers
Electrolyser manufacturing
Small-scale Haber-Bosch
Minimal boil-off storage
Hydrogen-combustors
Figure 3.21
Source: Wood Mackenzie, Lux Research
Hydrogen leak detection: Odorant or other means to quickly detect potentially dangerous hydrogen leaks without sensors
Fuel cells
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
146 147
CCUSThe CCC anticipates carbon capture, utilisation and storage to be critical technologies to decarbonise not only the UKCS, but also the UK overall. The UK’s ability to store CO2 in depleted oil and gas fields or saline aquifers, as well using detailed subsurface knowledge or leverage existing infrastructure, such as legacy pipelines or inactive platforms, is central to the UK’s decarbonisation.
CCUS has the potential to prevent millions of tonnes of anthropogenic CO2 from entering and remaining in the atmosphere and could play two pivotal roles in the future of energy in the UK, through: • direct abatement of onshore and offshore CO2 via sequestration; • indirect enablement of the integrated energy system, starting with
blue hydrogen
3.5:
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
148 149
Value chain overview Multiple technologies must come together to effectively capture and store CO2. Figure 3.22 illustrates a generalised CCUS value chain: CO2 is first captured and separated at point sources like large power plants, blue hydrogen facilities or natural gas processing plants296, or potentially offshore platforms. Once captured, the CO2 must be cleaned, compressed and then transported by pipeline or ship to storage sites, such as depleted hydrocarbon fields and saline aquifers, used for enhanced oil recovery (EOR), or converted into other products using chemical processes. The following sections will look at the technologies involved at each stage of the CCUS chain to identify key bottlenecks to achieving large scale deployment.
CO2 captureMany first generation CO2 capture or separation technologies have been deployed commercially for decades. These are limited to applications that either have a direct use for captured CO2, such as beverages, EOR, or pharmaceuticals, or applications in which product standards require separation of CO2 from the end product (most of this CO2 is vented since there is no incentive to store it), such as natural gas processing or hydrogen-rich syngas production that makes ammonia. Because of their large footprint, high capital costs, environmental logistics associated with solvent disposal and several other challenges, CO2 capture technologies have primarily been focused onshore. Likewise, the bulk of future CO2 capture in the UK is most likely to occur at onshore industrial hubs: Teesside, the Humber or St. Fergus. Currently, only a handful of small-scale CO2 capture projects are located offshore and this is unlikely to change in the long-term.
Figure 3.22: CCUS value chain
Table 3.22: CO2 capture processes
CO2 capture from point sources
Enchanced oil recovery and storage
Conversion into value added productsGeological storage
Transportation by pipeline or ship
Separation
Conditioning: clean-up and compression
PROCESS DESCRIPTION
Pre-combustion capture Solid or liquid fuels are first reformed or gasified, yielding a combination of hydrogen and CO2. The CO2 is then separated, and the hydrogen can be used as a fuel.
Oxy-combustion captureSolid or liquid fuel is combusted using a pure oxygen stream instead of air, yielding a near-pure stream of CO2 and water which can easily be separated.
Post-combustion captureCO2 is separated from exhaust gases after combustion has occurred. This is the most common process used in large power plants and industrial facilities.
Source: Wood Mackenzie, Lux Research
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
150 151
Many technologies can be used to separate CO2 from gas streams. First generation capture technologies are primarily chemical amine solvents297 that selectively absorb CO2 from gas streams in a packed bed absorber and release it when heated in a stripper. The solvent is thus regenerated and pumped back to the absorber for cyclic use. Depending on the intended use, the pure CO2 gas is either vented, or moves to a compressor to be prepared for transportation, utilisation or storage.
Other next generation technologies for separation include selectively permeable membranes, solid sorbents, cryogenic separation (using cooling and condensation to separate CO2) and calcium and/or chemical looping (reversible binding of CO2 to calcium or a metal oxide, respectively).
Table: 3.23: Improvement potential of capture technologies305 Figure 3.23: Options for CO2 capture offshore
To date, the majority of research, development and funding has been focused on CO2 capture at highly emissive onshore industrial sites, such as large power plants and more recently, heavy industrial emitters such as steel and cement factories298. The UKCS currently produces more CO2 emissions than any of the UK’s industrial clusters (Humberside produces 12.4 MtCO2e/yr and is the highest emissions cluster). Commercial factors make capturing CO2 offshore challenging, nevertheless there are two points on the UKCS where either CO2 separation or capture could be considered: natural gas processing and post-combustion CO2 capture
Solvent Solid sorbent Calcium looping
Chemical looping
Polymeric membrane
Capex
Opex
Depletion of capture material
Toxicity of capture material
Retrofit potential
Low Medium High
(see figure 3.23). Post-combustion capture on the UKCS will be particularly challenging because of the low CO2 concentrations in gas turbine flue streams, typically 3% to 6%.
A third major source of offshore CO2 is flaring, but CO2 capture is not a feasible abatement strategy. That has been addressed in the Oil and Gas section of this report.
Separation Natural gas processing Gas turbines Steam cycle
Post-combustion CO2 capture
Oil
(Onshore) Steam methane reforming,
power plant, industrial combustion
Well steams
98% CO2
99-100% CO2
5-15% CO2 Fuel gas
Fuel gas
CO2 + exhaust CO2 + exhaust
3-5% CO2
Other impuritiesExport + lift
+ injected gas
Point A: CO2 is separated from natural gas, which typically contains 90% methane and hydrocarbons like ethane and propane, plus smaller amounts of nitrogen, oxygen, CO2, sulphur compounds, and water, where the exact composition will depend on the individual site.
Point B: CO2 could be captured post-combustion from gas turbine and steam cycle (powering the platform) emissions. Economics, space and weight constraints, and viability of other abatement strategies such as fuel switching or electrification make post-combustion capture highly unlikely offshore.
These power the entire platform, including well operations, living quarters, processing, etc.
Source: Adapted from: Nguyen, T., Tock, L., Breuhaus, P., Maréchal, F. and Elmegaard, B.(2016).
Mid-term improvement potential over 1st generation technology
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
152 153
Natural gas processing
Current status
Extraction of natural gas produces a mixture of hydrocarbons, CO2, water, N2, H2S and other gases. Wellhead gas with higher impurities must be processed. In the UK, offshore platforms and onshore hubs such as Teesside and St. Fergus vent captured CO2 into the atmosphere.
Although CO2 capture technology associated with offshore natural gas processing is not widely deployed, it is used at fields with high CO2 content. There are no examples of this in the UK because of lower CO2 concentrations and a lack of economic incentives. Equinor operates two such projects in the Norwegian Continental Shelf: • The Sleipner Field produces natural gas
with 9% CO2. Combined with a carbon tax introduced in the 1990s, the economics of offshore separation and storage became attractive enough to build this first-of-a-kind project. Natural gas is processed directly on the platform and CO2 is injected into an aquifer. The Sleipner T project has been operational since 1996 and is a demonstration of how effective the technology can be, storing 1 MtCO2/y300.
• The Snøhvit field produces natural gas through a subsea operation with between 5% and 6% CO2 content. Wellhead gas is tied back to an onshore LNG plant at Hammerfest, where CO2 is separated and injected into a formation below the reservoir, storing 0.65 MtCO2/yr301.
All of the early commercial demonstrations of CCS in natural gas processing, including the Snøhvit and Sleipner projects, use first generation amine solvent technology302.
Post-combustion capture from natural gas turbines
Current status
Post-combustion CO2 capture is the most established capture technology. However, efforts for deployment are focused onshore, where implementation is operationally easier and much larger quantities of CO2 can be captured. Offshore gas turbines produce low concentrations of CO2, typically between 3% and 5%, yet large pre-treatment units would be required. Space constraints on platforms make deployment of the technology logistically and economically unfeasible offshore.
Centralised offshore capture concepts have thus been proposed, in which emissions from multiple nearby platforms are collected and processed on a central fixed or floating platform. Such a system would circumvent space constraints and benefit from economies of scale for carbon capture. This concept, which has been proven in front-end engineering studies, needs to be further explored for large-scale feasibility. For the foreseeable future, mitigation of platform emissions through fuel switching to hydrogen or through electrification is a more likely carbon abatement strategy on the UKCS.
Technology challenges
The most obvious challenges with offshore capture technologies are high capital costs and space constraints. All cases described above would require buildout of an adjunct platform to host equipment, which is simply not economically viable without hefty carbon prices, especially for ageing platforms303.
Onshore and offshore, several factors affect the economics of CO2 capture. First, the lower the concentration of CO2 in the gas stream, the higher the capture surface area, capital cost, and energy required for separation. Second, dirtier post-combustion gas streams, such as those found in power plants304, require expensive pre-treatment process units like blowers, pumps and compressors to filter out impurities and maximise efficiency of the CO2 capture technology, which also drives up capital and energy costs305. Finally, operating costs are also affected by inherent limitations of the capture materials. For example, first generation amine solvents require roughly 2.5 GJ/tonne CO2
320 for solvent regeneration, which if very good heat integration opportunities are not available, can lead to around 30% energy penalty in power stations, or around £45 to £55 per tonne CO2
306. In post combustion capture, amines can be quickly depleted in the presence of contaminants305. Economic constraints stemming from these technology challenges result in average post-combustion CO2 capture rates in the 60% range, though up to 95% is technically possible.
For the foreseeablefuture, mitigation of platform emissions through fuel switching to hydrogen or through electrification is a more likely carbon abatement strategy on the UKCS
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
154 155
Emerging capture technologies (second and third generation) mitigate some of these challenges in specific industrial applications307. Polymeric membranes work by pushing high pressure gas mixtures across highly structured membranes that selectively filter CO2 and N2
308. Solid sorbent processes selectively adsorb CO2 without forming chemical bonds, preventing environmental issues with liquid solvent disposal and lowering energy requirements for sorbent regeneration. Looping technologies can deliver pure oxygen streams to combustion chambers, while decreasing the energy requirements to regenerate CO2 carriers. Other innovations combine novel CO2 capture materials with engineering to form flexible, hybrid solutions. In the long term, technologies such as direct air capture could also be deployed onshore as a complement to onshore or offshore bolt-on capture solutions, compensating for residual CO2 that is uneconomical to capture directly from plant emissions.
Table 3.24: Technology challenges of CO2 capture
CO2 CAPTURE INNOVATION GAP
Capture materials (sorbents, solvents, membranes, others): high-capacity CO2 capture materials with minimal energy requirements for regeneration, low toxicity, and long lifetime
High capex: configurations and engineering solutions that minimise capex required for CO2 capture, particularly in large-scale post-combustion capture
Flexibleandretrofit-friendlycapture: engineering solutions that allow bolt-on CO2 capture to side-step requirements for large footprint permanent structures
Subsea separation: capture technologies that function subsea to unlock cheaper offshore CO2 separation closer to point of storage
Direct air capture: technologies to decouple CO2 capture from point sources, which can unlock flexibilities in a facility’s approach to full carbon abatement
Critical gap, unlikely to be resolved without strong effort Needs additional effort On track to be resolved
CO2 transportAchieving the CCC’s Further Ambition scenario will require significant buildout of CO2 pipelines, or repurposing existing pipelines, to transport CO2 from source to storage sites. Depending on the distance, captured CO2 can be transported via pipelines or storage tankers on ships. There are ongoing studies on the potential to reuse existing oil and gas infrastructure to transport CO2, rather than having to build new pipelines, considered feasible at distances greater than 350 km320, in order to save on capital costs.
PipelinesGlobally, there are over 8,000 km of CO2 pipelines in operation; most of these are in mainland US and were built in the 1980s and 90s to transport naturally sourced CO2 for enhanced oil recovery (EOR)310,311. In the North Sea, there are only two CO2 pipelines in operation, both in Norway. These are used to connect Equinor’s two CO2 storage sites in Sleipner and Snøhvit.
Current status
CCS projects on the UKCS have proposed repurposing existing gas pipelines for CO2 transport as a way to build out a CCS value chain more quickly and at lower cost. Retrofit costs will ultimately depend on the current state of legacy pipelines. Differences between natural gas pipelines and CO2 pipelines are minimal and centre on the level of controls required to maintain safety and asset integrity over time – especially in the case of anthropogenic CO2
312,313. CO2 is usually condensed and transported at super critical conditions (between 12°C to 44°C and 85 bar to 150 bar314). Even small variations in temperature and pressure can significantly alter flow rates and overall pipeline safety, meaning that CO2 pipelines
often require more meters, pumps and controls to maintain conditions. Additionally, anthropogenic CO2 is more likely to contain contaminants and trace amounts of water and oxygen, which could form corrosive acids over time312. This would need to be controlled with corrosion-resistant pipeline materials or through additional purification measures at loading.
Offshore CO2 pipelines will most likely comprise of carbon steel or stainless steel alloys with polypropylene coatings. Thicker pipelines will use concrete coatings. Onshore CO2 pipelines are fitted with metering devices that ensure safe transport conditions and detect cracks, in which are common in high pressure systems. As anthropogenic CO2 is more likely to contain corrosive contaminants, these measures will be even more important to protect asset integrity over time315,316. Multiple industry-led studies, including CO2PIPETRANS, continue to study the effects of different CO2 compositions, flow rates and external conditions on pipeline performance and integrity317,324.
The first project that will truly explore the viability of repurposing infrastructure is the Acorn project, a CCS initiative to collect industrial CO2 – initially from the St. Fergus terminal in Scotland – and store it about 100 km offshore. This project, currently in Phase 1, is looking to avoid the traditionally high capex usually associated with new pipeline and platform construction by repurposing the ageing Atlantic, Goldeneye or Miller Gas pipelines that are suspended and close to decommissioning318. Preliminary results from a 2018 ACT Acorn Feasibility Study319 indicate that repurposing ageing pipelines could cost about 75% less than building something new; however, more recent assessments320 revealed that required asset integrity inspections and rectifying pipeline corrosion could increase the overall capex up to four-fold.
Compact carbon capture:• Compact Carbon is developing a
containerised, modular lightweight spinning CO2 capture system that uses G-forces to distribute any CO2 solvent throughout the stack. The company claims that it is solvent-flexible, can process CO2 concentrations between 4% and 50% and delivers fully compressed CO2 ready for transport or storage11.
• Aker Solutions has developed Just Catch, a modular, containerised CO2 capture solution with a capture capacity of 0.1 MtCO2/year. The solution claims to have easy plug-and-play installation, a minimal 18m x 25m footprint, remote controlled operation and low cost. In addition to several demonstrations, the solution has been deployed at Twence’s waste to energy plant in the Netherlands, due to be in operation in 2021309.
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
156 157
Technology challenges
CO2 transportation is technologically well-understood; cost is the main deterrent. However, there are still technology challenges related to retrofits, long-term integrity and monitoring, which could be solved through oil and gas industry know-how.
ShippingShipping CO2 for commercial use, such as in the food and beverage industry, has been in operation for almost 30 years. However, those operations are on a 1,000 tonne CO2 scale, which is at least two orders of magnitude smaller than what industrial CCUS would demand321. Full scale CO2 tankers are very similar to commercial, semi-refrigerated LNG tankers, but any larger capacity ships would require significant redesign to accommodate the harsh conditions of the North Sea321.
Shipping CO2 in tankers could serve as a near- to mid- term solution to help demonstrate multiple CO2 storage sites in the <1 MtCO2/yr scale without the enormous capital outlay that is required to build pipeline infrastructure each time. To date, that has been a major deterrent in the scale-up of CCUS technologies321. More importantly, flexibility afforded by shipping could also help to open UK storage sites to other European countries, which could be a linchpin to establishing international demand for this unique and vast resource on the UKCS.
CO2 transport ships will likely need to be built for purpose at roughly 0.05 MtCO2 to 0.1 MtCO2 capacities322 - although companies like Yara International and Anthony Veder do have dual-purpose LNG/CO2 ships321,322,323. Despite industry hesitancy on whether flexible containers are viable and the lack of regulatory frameworks, shipping does not present any major technology hurdles. On the contrary, it provides a viable option for longer distance and lower volume CO2 transport324.
Aker Solutions is working with Equinor, Shell and Total on the Northern Lights CCS project. Industrial CO2 that has been captured onshore or imported to Øygarden in Western Norway, temporarily stored, before being injected about 2.8 km beneath the seabed in the Johansen and Cook aquifer. As of early March 2020, Equinor drilled and temporarily sealed a wildcat well to characterise this formation’s viability for large scale CO2 storage. Initial results were all positive and the final investment decision for the project was made by the industrial partners in May 2020325.
Table 3.25: Technology challenges of CO2 transportation
CO2 TRANSPORTATION INNOVATION GAP
Corrosion: characterisation and coatings & materials solutions to prevent corrosion from contaminants present in anthropogenic CO2
Crack propagation: predictive maintenance solutions to prevent crack propagation and ensure pipeline integrity
Pressure control: low-cost control valves to maintain consistent pressure, especially in longer pipelines
Retrofitabilityofageinggaspipelines: clear understanding of cost and methodology to retrofit legacy gas pipelines
Critical gap, unlikely to be resolved without strong effort Needs additional effort On track to be resolved
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
158 159
CO2 storage Post capture and transportation, CO2 can be stored in one of the UKCS’ many oil and gas reservoirs or saline aquifers under the seabed. Several storage sites have been nominated as high-priority storage clusters because of their known physical geological attributes.
Current status
Oil and gas operators on the UKCS have been collecting subsurface data for decades, providing a solid foundation for characterising potential storage in saline aquifers or depleted oil and gas fields.
Researchers are still debating whether aquifers or depleted fields are better suited for long-term storage but agree that removing residual oil and gas from fields improves outcomes326. Ideal aquifer formations have salinity in excess of 10,000 ppm327and are highly permeable (to prevent build-up of pressure leading to potential leakages or man-made seismic events) with strong caprock seals (see figure 3.24). Operators have also deployed secondary trapping mechanisms, such as dissolving CO2 into aqueous pore fluid, using capillary forces to trap residual gas and purposeful mineralisation via CO2 reacting with pore fluid and rock328 to further lock in CO2. While many small field trials and front end engineering design (FEED) activities have been completed on the UKCS, there are no CO2 storage projects that utilise geological storage sites currently in operation.
Technology challenges
Despite familiarity and availability of geospatial data that characterises UKCS basins, many technology and knowledge gaps exist. These gaps include problems with data availability, interoperability of different data sets and the ability to model the behaviour of CO2 over time.• Robust multi-variable CO2 modelling: Many valuable tools exist today, but
there is significant room for improvement. The industry needs standard methods to model CO2 migration and interactions329 in different rock structures and potential cracking and chemical reactions through the different stages of storage (including pre-injection, operational lifetime and after sealing the injection site)330. This is particularly critical around existing wells, which could present a higher risk of leakage.
• Site selection and injection strategy: Since disparate data sets are very difficult to compare, like-for-like comparison of key metrics during site selection becomes challenging331. Different storage sites also require different injection strategies to optimise storage efficiency. That means that additional research and development combined with data on hydrocarbon behaviour prior to extraction is needed332.
• Phase management of CO2: CO2 behaves very differently in its different phases, which can significantly affect trapping mechanisms post-injection. This phenomenon needs to be carefully studied across the different rock formations present on the UKCS, particularly in highly depleted gas fields332.
• Low cost long-term monitoring: While there is some cross-project learning, the industry lacks a standard set of tools and guidelines to establish safe long-term monitoring of storage sites330,331.
Table 3.26: Technology challenges of CO2 storage
CO2 STORAGE INNOVATION GAP
Modelling, site selection, injection strategy: more robust modelling and data interoperability to improve understanding of CO2 behaviour in informing site selection and injection strategy
Geological behaviour of CO2: improved characterisation of in situ CO2 behaviour in different injection sites
Site monitoring: standardised, low-cost long-term monitoring of CO2 post-injection
Critical gap, unlikely to be resolved without strong effort Needs additional effort On track to be resolved
Figure 3.24: CO2 storage sites and trapping mechanisms
1. CO2 is captured at the emissions source before gases are released into the atmosphere
2. CO2 is compressed and transported via pipelines to an injection site
Onshore emissions source
Platform
CO2 transport ship
Aquifer
Depleted gas field
4. CO2 leaves the injection well and fills pore spaces in depleted hydrocarbon reservoirs. As more CO2 is injected into the site, CO2 moves out through the formation.
2. CO2 is compressed and transported in ship tankers to an injection site
3. CO2 is injected via wells into subsurface, porous layers
5. As with oil and gas fields, an impermeable cap/seal unit is needed to trap the CO2 in the reservoir and prevent it reaching the surface.
4. CO2 can be injected into aquifers where it is dissolved in saline water and permanently stored.
Inje
ctio
n w
ell
6. Storage sites will need to be monitored to ensure permanent storage.
Source: Adapted from: Energy Technology Institute
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
160 161
CO2 utilisation Onshore utilisationCarbon utilisation is an emerging group of technologies that convert or directly use captured CO2 to create value. The main uses of captured CO2 are onshore and include conversion into energy or fuel, microbial fermentation for chemicals and food ingredients and catalytic conversion for chemicals and materials333. CO2 is a chemically stable molecule and so novel chemical, or catalytic conversions tend to be energy intensive and are largely in the development stage. Nevertheless, uptick in downstream demand from environmentally conscious consumers is driving extensive start-up and corporate activity, as well as sizeable investments from ventures, corporations and governments333.
Utilisation has an important role to play in creating market demand for CO2 as a feedstock. For example, stricter emissions regulations in the marine sector are driving ship operators to explore lower carbon fuels such as methanol, which can be directly produced from CO2. However, this demand will never be sufficient to abate a meaningful portion of the CO2 that is emitted on the UKCS and the UK. Finding new markets in the petrochemical or food industries can help to create new revenue streams for CCUS. However, geological storage will likely be the most scaleable CCUS option.
Figure 3.25: CO2 utilisation pathways
Carbonated beverages
Food products
Enhanced oil recovery,enhanced gas recovery,
enhanced coal bed methane
recovery
Fire suppresion
Miscellaneous
Miscellaneous
Miscellaneous
Biological conversion
Ingredients
Shield gas in welding blanket
products
Inerting agent
Refrigerant
Fertilisers
Chemicals
Mineralisation
Plastics
Supercritical extraction
Captured CO2
Aerosol can propellantMedical gas, Red mud carbonation
Fire extinguishers
Dry ice pellets for ice blasting
Flavors/fragrancesDecaffeination
Methanol, Urea, CO, Methane
PolycarbonatesOther polymers
Refrigeration Dry ice
Algae
Liquid fuels
Fuels
Secondary chemicals
Oil and Gas
Carbonates
Source: Wood Mackenzie, Lux Research
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
162 163
Offshore utilisation
Current status
Globally, enhanced oil recovery (EOR) is the primary use of CO2 offshore. EOR involves injecting combinations of pressurised fluids and gases into rock formations, pushing out oil that would otherwise be trapped in rock pores. In CO2 EOR, injected CO2 becomes permanently trapped and the remaining CO2 solvent is recovered, along with residual oil, brine and other fluids and reinjected; eventually, all injected CO2 remains stored underground334,339. EOR is already used in the UKCS but relies purely on readily available materials (water, associated gas and polymers)335,336 instead of captured CO2. Despite a stated target337 to implement EOR, uptake has been slow because of higher fixed platform, pipeline and operating costs that contribute to higher breakevens. A 2018 review estimated that a Brent price of between £66 and £76/bbl would be required for CO2 EOR projects to be viable338.
More than 260 million tonnes of CO2 have been sequestered globally through EOR activity – the majority through onshore EOR in the US339. Despite its success onshore and potentially favourable geological advantages offshore340,340, in situ offshore conditions (such as high temperature and reservoir heterogeneity) combined with the lack of an attractive CO2 scheme make the economics unfavourable on the UKCS336,341.
While there have been at least six small scale pilots (Vietnam, Gulf of Mexico), there is only one offshore CO2 EOR project in operation: the ultra-deepwater Lula field in Brazil342. The field produces associated gas containing roughly 11% CO2. A strategic decision to avoid venting CO2 and enhance oil recovery led operators to design a system that is flexible enough to inject enriched CO2 or associated gas343. Producing roughly 800,000 boe per day this project is the most productive ultra-deepwater field in the world and is expected to ramp up to around 1 million boe per day at peak production344.
Technology challenges
Most onshore CO2 utilisation pathways need significant development before large, commercial scale deployment can take place. For CO2 EOR345, the UKCS struggles with several practical, macroeconomic and policy challenges that are preventing adoption. In addition to the innovation gaps related to CO2 storage, key technology challenges include:• Equipment: space and weight restrictions on existing offshore platforms
limit viability of large footprint CO2 equipment like compressors and recycling units. A large centralised CO2 processing unit, as described in the CO2 Capture section, could circumvent several challenges in individual platform injection, including lower flow quantity, variable flow, and physical constraints. This concept needs to be further explored for economic and logistical feasibility.
• Subsea technologies: while all of the components for gas processing are already commercially available, adapting these to subsea conditions could be critical to bringing down system cost.
Technology accelerators, enablers, and dependent technologies
Unlike hydrocarbons or renewables, the CCUS value chain is still in its infancy in the UK. Regulation, consumer lobbying and operational realities are driving many industries to demand and improve capture technologies onshore, which will primarily be realised in petrochemical clusters that are located near to the UKCS.
While CO2 utilisation is also being driven by downstream demand for sustainability in industries like cement, steel and marine, the development of transportation and storage infrastructure for CO2 will require significant government funding and industry collaboration for a successful rollout.
The UKCS’ vast storage potential is an important resource in decarbonising not only the UK but also its European neighbours; harnessing the European CCUS market will help build and establish the UK’s position as a global authority on CCUS.
Most importantly, establishing the CCUS value chain will be critical to unlocking low-carbon energy sources such as (blue) hydrogen, whose prospects rely on the viability of onshore CO2 capture and storage on the UKCS.
Table 3.27: Technology challenges of CO2 utilisation
CO2 UTILISATION INNOVATION GAP
Compact CO2 processing equipment: low-cost, compact processing equipment to enable offshore CO2 handling for EOR
Subsea separation and CO2 injection: (see CO2 capture and Oil and Gas sections)
HighefficiencyCO2 conversion: low-cost CO2 utilisation pathways to value-added products
Critical gap, unlikely to be resolved without strong effort Needs additional effort On track to be resolved
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
164 165
CCUS ecosystem and path to 2050 Near-termThe 2018 UK government’s “Delivering Clean Growth: CCUS Cost Challenge Taskforce Report” recommended that the UK have at least two CCUS clusters operational in the 2020s, anchored by catalyst projects that would enable ‘learning by doing’ – a common theme among CCUS developers around the world. While the UK has no operational CCUS projects as yet, the CCC’s Further Ambition scenario cites a 2050 capacity storage goal of 176 MtCO2/y. Despite the thirty-year runway, initial projects take up to eight years each305 before they can begin injection: site selection, completion of FEED stages, securing funding, ironing out complex ownership and building the required infrastructure. Many of the knowledge gaps discussed here can only be filled through experience.
The March 2020 budget announcement pledges £800 million to develop two CCS projects by 2030, which will help move CCS down the cost curve and establish much-needed transportation infrastructure through two key CO2 pipelines. Construction of these pipelines will demonstrate the value of retrofitting the UKCS’ existing infrastructure and create incentive for more members of neighbouring industrial clusters to consider implementing CO2 capture technologies. The UK will also need a strong pipeline of at least two more projects between now and 2035339. Building these catalyst projects will also unlock a path to infrastructure buildout through pipelines. Shipping can help to expand project footprints beyond initial pipeline connections. Meanwhile, technical feasibility and cost of repurposing other ageing pipelines and platforms should be thoroughly investigated in the near term before UKCS decommissioning activities accelerate.
Mid-termTechnologies that are in their infancy today (subsea gas separation and compression, third generation capture technologies, CO2-to-chemicals and blue hydrogen) will need to be entering CCUS pilots. By 2035, onshore CO2 capture costs will need to reduce by an additional 10 to 15%, buoyed by the construction of at least one additional CO2 pipeline and from the lessons learnt from two fully built CCUS clusters. While subsea gas processing and capture technologies (for example, enabled by membranes for compact systems) will be cheap enough to integrate into strategically located and newly built platforms, the majority of captured CO2 will still come from onshore capture projects in major industrial clusters such as St. Fergus and Teesside. The buildout of a CO2 shipping infrastructure should also open storage sites to international players, enabling more rapid expansion and opening new revenue streams to the UKCS. Finally, CO2 utilisation, through conversion into valuable chemical intermediates like methanol, will further spur industrial interest in adoption of capture technologies.
Long-termFrom 2040 and beyond, CCUS will need to grow into a functional, scaleable industry, building on the learnings and risk mitigation from the first clusters that would have been established in the 2030s. Demand for blue hydrogen will continue, but onshore industry emissions will need to claim much of the CO2 capacity connecting to at least four operational storage clusters. To achieve net zero carbon by 2050, all new production platforms will need to be using hydrogen or be fully electrified. Demand for CO2 (mostly through strategic carbon pricing set by the UK government) will need to have changed CCUS into a standalone industry.
Reducing costs and improving the CO2 capture efficiency will improve CCUS feasibility. To realise the full storage potential of the UKCS better modelling of CO2 subsurface behaviour will be required. In parallel, for CCUS to succeed, firm government support is necessary. When first-of-a-kind project costs can exceed £800 million339 investors need a robust business case and this will require coordinated financial and policy support. With 62 operational CCUS projects around the world and none yet in the UK, rapid progress is required to meet national net zero commitments.
Speculative technologies for CCUSCO2 electrolysis
• Decomposition of CO2 into chemicals using electricity, under development by Siemens, Sunfire, and others.
• On-site production of higher-value chemicals for easier transport. When coupled with water electrolysis, it can lead to the production of syngas for downstream processing.
Electrochemical direct air CO2 capture
• Electrochemical plates react with CO2 in the air, capturing it. The reverse reaction delivers power and ejects a pure stream of CO2.
• Capture of CO2 even at different concentrations, including 400 parts per million found in the atmosphere.
Allam Cycle power generation
• Oxy-fuel combustion of natural gas with a mixture of oxygen and recuperated supercritical CO2. This is fed through the turbine, after which water is condensed and separated out.
• CO2 and heat are recuperated after the turbine and fed back into the process. Excess CO2 from the process is high purity and so directly suited for storage or utilisation.
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
167166
2020 2035 2050
CCUS technology roadmap
Short-term Mid-term Long-term
Capture materials (sorbents, solvents, membranes, others): high-capacity CO2 capture materials with minimal energy requirements for regeneration, low toxicity, and long lifetime
Flexible and retrofit-friendly capture: engineering solutions that allow bolt-on CO2 capture to side-step requirements for large footprint permanent structures
Subsea separation: capture technologies that function subsea that can unlock cheaper offshore CO2 separation closer to point of storage
Geological behaviour of CO2: improved characterisation of in situ CO2 behaviour in different injection sites
Compact CO2 processing equipment: low-cost, compact processing equipment to enable offshore CO2 handling for EOR
High efficiency CO2 conversion: low-cost CO2 utilisation pathways to value-added products
Direct air capture: technologies to decouple CO2 capture from point sources, which can unlock flexibilities in a facility’s approach to full carbon abatement
Ecosystem
• Capture development continues to be driven by industrial demand from high emitters like cement or fertilizer production.
• Pipeline development contingent on successful pilots, where business models and ownership are established. These pilots can unlock blue hydrogen as they’re scaled up from initial injection sites.
Ecosystem
• Successful pilots in near-term lead to CCUS cost reductions through efficiencies and learnings from experience.
• Demand for CO2 storage needs to be built in the mid-term, and is directly linked to successful implementation of a clear and consistent CO2 policy in the UK.
• Meanwhile, storage demand from neighbouring countries can also increase the UK’s economic recovery of the UKCS, through shipping or transcontinental CO2 pipelines.
Ecosystem
• Despite development of highly efficient solutions, onshore capture hits price ceilings, where capturing residual point CO2 emissions no longer makes economical sense. In the long-term, direct air capture could be a viable supplement for operators to address residual CO2 emissions to achieve net zero economically.
• Progress in CO2 utilisation technologies could also provide flexible outlets for petrochemical cluster emissions, while creating value-added products.
Capture
Transportation
Storage
Utlisation
“incremental gain” tech challenges that will get resolved with or without
dedicated effort
Critical path
Parking lot
High capture capex
Pipeline corrosion & crack propagation
Pipeline pressure control
Retrofitability of ageing gas pipelines
Modelling, site selection, injection strategy
Site monitoring
Figure 3.26
Source: Wood Mackenzie, Lux Research
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
168 169
DIGITALISATIONOver the last decade, digital technologies and the industrial internet of things (IIOT) have allowed oil and gas operations to run faster and more efficiently, reducing costs by up to 30% and completing projects up to 25% faster346. The role of digitalisation will continue to grow on the UKCS. It will become a central enabler for renewables and hydrogen technologies to be integrated with the UKCS energy system, and will allow the oil and gas sector to decarbonise further, electrify and move more operations subsea.
3.6:
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
171170
Ecosystem and path to 2050 The role of digitalisation in an integrated energy systemCreating an integrated energy system on the UKCS will require digital technologies to be developed and used in parallel across the oil and gas, hydrogen, CCUS and renewables sectors. A system that coordinates the operations of these four sectors as a single unit will become crucial.
Overall, digital technologies will deliver six key benefits to the different steps in the value chain of the integrated energy systems (see figure 3.27).
Appraisal and developmentDigitalisation will help in the planning stages of any project. For the construction of new power generation capacity, digital systems already help to map resources and determine the best sites, depending on wind availability or wave potential. The use of big data and forecasting algorithms to model and evaluate possible future scenarios can further help during the integration phase of renewables, hydrogen and CCUS projects. Such scenario modelling systems will serve, for instance, as tools to assess the likelihood and extent of potential future stressors on the new offshore energy system. This information will help to plan energy back-up infrastructure or connections to onshore generation and storage capacity without incurring excessive costs.
Figure 3.27: Digitalisation across the energy value chain
Valu
e pr
opos
ition
of d
igita
lisat
ion
Appraisal and development Appraisal, planning, design,
engineering and construction activities for all types of new energy
facilities and infrastructure.
Operation and production
Optimisation of operations across energy systems to drive
improved performance, increased safety, and to enable the
integration of complex energy systems.
Management of product flow
Integrated energy system
Managing interdependencies within the integrated energy system on the UKCS and their interface with the onshore grid and networks.
This will include balancing of power requirements, offshore consumption, storage, bi-directional transportation
and distribution.
Reduced maintenance costs
Resource mapping
Asset visualisation
Automation
Efficiency optimisation
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
172 173
Digital Twins Safety assurance Smart contracts
A digital twin is a virtual replica of a piece of equipment that operators can use to test new software or other modifications, or feed with real-time data from connected sensors, to predict failures and optimise performance352. For instance, Norske Shell doubled the lifetime of ageing topside and subsea assets while reaching a 99% uptime with high levels of safety and energy efficiency353. Digital twins already help wind farm operators to optimise maintenance strategies, improve turbine reliability and availability and increase annual energy production354.
Digital technologies can improve safety by better informing workers, or by removing human risk altogether with autonomous operations. Since 2017, Innogy has been deploying drones to carry out inspections at the Nordsee Ost wind farm off the German coast. Drones avoid the need for industrial climbers to carry out inspections, while reducing the downtime of wind turbines as less time is required to complete an inspection. Remote inspection and maintenance will continue to improve as companies develop their analytics and imaging systems to improve fault identification.
Digital tools can enable new business models like smart contracts with performance-based rewards. Aker BP and Framo have signed a deal in which Framo uses sensor data from seawater pumps to predict performance and ensure uptime and is paid based on uptime delivered355.
Operation and productionWith the widespread availability of sensors across platforms and power generation equipment, technologies such as digital twins will further enable the visualisation of all relevant parts in the integrated energy system. They will ease the management of assets off-platform, such as subsea production systems, offshore substations and different types of generation assets. In the wind energy industry, services based on digital twins are now common for operations. These service build on existing control tools used for wind turbines347. In this way, in-field performance of turbines is compared to the digital twins to identify faulty components, improve operational parameters and apply predictive maintenance. Such visualisation and simulation tools can also provide oil and gas operators, engineering, procurement and construction companies (EPCs), service companies and stakeholders in the power sector with an environment that allows them to work together to streamline projects, design equipment in synchrony and form best practices348.
Digitalisation will be important in enabling the UKCS to reach its net zero target through modeling and validating of the potential outcomes of low-carbon technology implementation. Understanding how any solution might impact capex and opex in the long term, i.e. through changing fuel and energy usage and CO2 tax implications, will be imperative before new technologies are deployed.
Digitalisation can help optimise continuous processes to maximise operational efficiency. In this way, sensor data and machine learning algorithms determine the optimal setpoints to maximise well production, for example in artificial lift applications349. Control algorithms will also help to ensure that electrolysers for hydrogen production operate at maximum efficiency350.
Digital systems enable automated operations in platforms, reducing personnel requirements. Similarly, equipment inspections can be scheduled automatically and carried out by unmanned
vehicles that capture images of infrastructure and automatically identify physical anomalies. This has the potential to not only reduce maintenance costs, but also improve safety in offshore operations351.
Integrated energy systemAs electricity from renewables starts to power oil and gas operations, energy management systems will play a prominent role in meeting power demand by coordinating power supply from different renewables’ sources, energy storage systems, or even onshore power capacity. Digital systems can plan the flow of energy from different resources by taking into account weather forecasts, market conditions and future energy demand either onshore or offshore. The distribution of hydrogen for offshore use via fuel cells or for onshore processing will also be based on these demand forecasts.
Standardisation on data handling, storage, sharing, and securityMost companies on the UKCS are using digital technology, but this lacks standardisation. For instance, most sensor data is not compatible across software platforms. This issue will be exacerbated as data points from equipment including wind turbines, energy storage, CO2 storage monitoring and subsea equipment come online. For digital technologies to reach their full potential, oil and gas companies need to create a digital ecosystem that supports the integration of software data across all operations by 2030. Furthermore, consortia standardising data from renewables, hydrogen, CO2 and oil and gas industries will be critical as the UK transitions to an integrated energy system. Naturally, data sharing presents considerable security risks, not only to the operators but to the energy security of the UK – so cybersecurity needs to be high on the agenda every step of the way356.
Implications for industry By 2030, predictive maintenance and automated operations should be common business practices, minimising risk of failures and disruptions, while maximising reliability and efficiency. That will bring major changes to the business models of companies operating on the UKCS. EPC companies will need to dedicate fewer resources to the upfront design stages of projects but will be able to offer monitoring and optimisation services through a facility’s lifetime357. Service contracts will evolve from fixed price models to outcome-based business models, which in turn will incentivise further investment in digital and automation technologies.
Beyond 2040, digital technologies will increasingly move UKCS operations to shore-side support, maximising the level of unmanned, autonomous and subsea development. That will have two important consequences for the sector. First, it facilitates more complex operations in harsh locations, through reliable automated or semi-automated remote operations. More importantly, it will have far-reaching consequences for employees– data science skills will become crucial, requiring multi-disciplinary teams with new talent. Recruiting a new generation of workers with digital expertise needs to begin in the near term, so that these new crucial skillsets can play a part in the decarbonisation of the UKCS and UK energy system.
Table 3.28: Case Studies
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
Clo
sing
the
Gap
to 2
050
Tech
nolo
gies
| Se
ctio
n 3
174 175
Integrated Energy Sytem Roadmap4
4.1: Changing UKCS landscapeAs the UKCS’ energy system grows in diversity and energy output, it will be made up of an increasingly complex mix of technologies that support the UK’s decarbonisation. On the path to 2050, the landscape will evolve from today’s siloed industries operating side-by-side, to an integrated energy system: one offshore industry where operations are interlinked, enabled by digital solutions.
Operational upgrades are already underway in the offshore oil and gas sector and, combined with the increasing presence of offshore wind, is leading to near-term progress in decarbonisation. As the UKCS evolves towards 2035, the renewable power grid will gradually integrate with the offshore oil and gas sector to electrify platforms (B in figure 4.3), while continuing to supply the UK mainland with power. It will also aid in the development of a hydrogen economy, through both green hydrogen (A in figure 4.3) and, as CO2 storage emerges, blue hydrogen (C in figure 4.3). Multiple CCUS and hydrogen pilots and demonstrations will be critical to establishing technology and business cases for these foundational decarbonising technologies as stepping stones towards a net zero UKCS in 2050.
Closer to 2050, operations will need to increasingly interlink and the lines between the offshore industries will blur with more CO2 storage and hydrogen (D in figure 4.3) being added to the mix.
The UKCS will need to evolve into an integrated energy ecosystem comprising a multitude of technologies, where complex operations across sectors are managed though widespread digitalisation and automation. The OGA’s UKCS Energy Integration report407 highlights the potential benefits of integration of offshore energy systems including improved economics of energy production and cutting greenhouse gas emissions. Figure 4.1 shows the current UKCS energy system and figures 4.2 and 4.3 represent a view of how an integrated UKCS energy system could look in 2035 and 2050 respectively.
Inte
grat
ed E
nerg
y S
yste
m R
oadm
ap |
Sec
tion
4
Inte
grat
ed E
nerg
y S
yste
m R
oadm
ap |
Sec
tion
4
179178
UKCS current reality 2020
Figure 4.1
Industrial Cluster
Petrochemical cluster
Power plant
Domestic supply
FPSO
OIL/GAS PIPELINEPOWER CABLE
Subsea development
Source: Wood Mackenzie, Lux Research
Concept shown is illustrative
Schematic view of the current set-up of UKCS energy system with stand-alone oil and gas and offshore wind.
Inte
grat
ed E
nerg
y S
yste
m R
oadm
ap |
Sec
tion
4
Inte
grat
ed E
nerg
y S
yste
m R
oadm
ap |
Sec
tion
4
181180
UKCS integrated energy vision 2035
Figure 4.2
Industrial Cluster
Petrochemical cluster
Hydrogen power plant
Domestic supply
Electrified FPSO
Power plantHydrogen production with CO2 capture
Energy storageMobile floating wind unit
CO2 injection facility
Wind with built in electrolysers (green hydrogen)
Wind power supplying oil and gas platform
Export interconnector
Energy hub
Subsea/floating substations
Ceased production platform
POWER CABLE
OIL/GAS PIPELINEHYDROGEN PIPELINE
CO2 PIPELINE
Subsea development
Floating wind
Electrified oil & gas platform
Electrified platform
Source: Wood Mackenzie, Lux Research
Concept shown is illustrative
Small pools reusable production system
Schematic view of how the UKCS could develop into an integrated energy system. In 2035 there needs to be increased integration
and repurposing of offshore energy infrastructure, i.e. offshore wind powering oil and gas production and oil
and gas platforms being used for CO2 injection.
Inte
grat
ed E
nerg
y S
yste
m R
oadm
ap |
Sec
tion
4
Inte
grat
ed E
nerg
y S
yste
m R
oadm
ap |
Sec
tion
4
183182
UKCS integrated energy vision 2050
Figure 4.3
Industrial Cluster
Petrochemical cluster
Hydrogen power plant
Domestic supply
Electrified FPSO
Power plant with CO2 storage
Hydrogen production with CO2 capture
Energy storage
Small pools reusable production system
Electrified platform
CO2 injection facility
Wind with built in electrolysers (green hydrogen)
Wind powering hydrogen production facility
Export interconnector
Energy hub
Subsea/floating substations
CO2 injection facility
POWER CABLE
OIL/GAS PIPELINEHYDROGEN PIPELINE
CO2 PIPELINE
CO2 direct air capture
CO2 utilisationElectrolyser plant (green hydrogen)
Mobile floating wind unit
Offshore operations control center
Repurposed pipeline
CO2 transport
Hydrogen transportGreen hydrogen production facility
Energy storage
Subsea development Subsea factory
Surface production system
Floating wind
Source: Wood Mackenzie, Lux Research
Concept shown is illustrative
Schematic view of how the UKCS could develop into an integrated energy system. In 2050 the UKCS needs to have developed into a fully integrated system of oil and
gas and hydrogen production powered by renewable energy, as well facilities for large scale CO2 transport and storage. Offshore energy
hubs and energy storage facilities will need to be developed to ensure the system is flexible
and runs efficiently.
Inte
grat
ed E
nerg
y S
yste
m R
oadm
ap |
Sec
tion
4
Inte
grat
ed E
nerg
y S
yste
m R
oadm
ap |
Sec
tion
4
185184
4.2: Development of an integrated energy system
A Multiple large-scale onshore electrolyser projects are already in development, some depending on power from offshore wind farms to make green hydrogen. Eventually, scale-up of green hydrogen will lower electrolyser capex through large-scale manufacturing. As industrial demand for low-carbon hydrogen continues to build a sustainable hydrogen market, falling costs and growing capacity of offshore wind power will drive green hydrogen scale-up and commercialisation – a more expensive, but available, alternative to blue hydrogen in the short term.
B Platform electrification will add considerable complexity to the offshore power grid. Ultimately, connecting a platform will require balancing power generation from offshore renewables against demand from other offshore assets, the onshore UK grid and international demand via interconnectors. Since this grid is in its infancy today, developers have the opportunity to design for flexibility, relying on features like bi-directional power flow, power quality management and energy storage in the form of batteries and hydrogen storage. These flexibilities will help prevent future grid congestion issues of the kind that plague the onshore power grid today.
C While existing steam reforming and carbon capture technologies can already produce partially decarbonised hydrogen, commercial scale-up of blue hydrogen firmly depends on scale-up of CO2 pipelines and storage in large-volume reservoirs.
D A developing hydrogen value chain on the UKCS benefits more than decarbonisation onshore. It creates opportunities to transport energy as hydrogen from far-from-shore wind farms via pipelines and store large volumes in reservoirs. Additionally, it can benefit further decarbonisation of the oil and gas sector as an alternative to platform electrification, especially for ageing assets where electrification is technically or economically not viable.
As the role of the UKCS evolves, several technologies will need to be developed in tandem and existing industries will begin to integrate with new industries to create a new landscape.
Integration of the UKCS energy system creates interdependencies, where commercial progress of one energy system impacts that of another. This calls for integration to be considered during technology development, rather than linking disparate technologies developed in isolation, as has been the approach to date. It is critical to
Figure 4.4: UKCS Integrated Energy System Roadmap2020 2030 2040 2050
Oil and gas
Subsea technologies
Advanced methane leak detection
Platform electrification
Flaring mitigation
Renewables
Fixed-bottom wind
Floating wind
Other renewables (esp. marine)
Offshore energy storage
H2
Hydrogen
Blue Hydrogen
Green Hydrogen
Hydrogen storage/transport
Fuel cells
Hydrogen turbines
CCUS
CO2 capture
CO2 transportation
CO2 storage
CO2 utilisation
Digitalisation
Digitalisation
A
B
C
D
Source: Wood Mackenzie, Lux Research
consider the technology roadmap for an integrated system and identify the key milestones and interdependencies.
Figure 4.4 illustrates the overall UKCS Integrated Energy System Roadmap, highlighting the critical cross-industry dependencies to build an integrated energy system:
Inte
grat
ed E
nerg
y S
yste
m R
oadm
ap |
Sec
tion
4
Inte
grat
ed E
nerg
y S
yste
m R
oadm
ap |
Sec
tion
4
186 187
4.3: Meeting the CCC targetsIn this section we have used the CCC’s Further Ambition scenario to get an appreciation of the required scale and pace of deployment of the technologies identified in the Closing the Gap to 2050 Technologies section of this report. The scenario focuses on achieving a high level of electrification, advancement of CCUS and deployment of hydrogen infrastructure in the UK. The CCC analysis concluded that the targets outlined in figure 4.5 would need to be reached by 2050 to achieve UK wide net zero emissions. Each of these targets was assessed by the CCC to identify the level of the feasibility.
Although the CCC provides no specific targets for oil and gas production, it does highlight the need for a reduction in methane venting and leakage. Oil and gas will continue to play a role in meeting the UK’s energy demand and so we have used the UK oil and gas industry’s Roadmap 2035 to forecast future production as this takes into account the CCC’s net zero target (see figure 4.6 - oil and gas production).
For the purposes of this report, and in assessing the role of the UKCS’ contribution to achieving the 2050 targets, the 2020 to 2050 forecasts of oil and gas production, offshore wind power generation, hydrogen production (assumed to equal hydrogen use) and CCUS capacity were evaluated. Our assessment combined:
• The CCC’s targets and notes on target ‘feasibility’• This report’s technology roadmap, including technology readiness, limitations/challenges• The existing/planned project pipeline • Other industry targets that aim to align with the CCC targets (i.e. the Roadmap 2035)
The resulting forecasts shown in figure 4.6 represent one pathway of how the 2050 targets could be achieved and what this would mean for the deployment of the different technologies. More work is being done by the OGTC and Offshore Renewable Energy Catapult (ORE catapult) to understand how different pathways could evolve. The Integrated Energy Vision report will be published in 4Q 2020. As recognised throughout this report, government policy, technology innovations and investment in new infrastructure will be required to support the scale and pace of technology deployment.
Figure 4.5: CCC Further Ambition 2050 targets
Source: Wood Mackenzie, CCC
Offshore renewables
2020: 10.5 GW
2050: 75 GW +65.5GW
(installed capacity)“Historical deployment rates suggest this sort
of deployment should not be a major issue”
CCUS
2020: <0.5 MtCO2
2050: 176 MtCO2
+176 MtCO2
(carbon captured and stored)“Requires CCS transportation and storage
infrastructure at scale by the 2030s.”
Hydrogen
2020: 27 TWh
2050: 270 TWh+243 TWh
H2
H2
H2
H2
H2
H2
H2
H2
H2
H2
H2
H2
H2 H2 H2 H2 H2 H2 H2 H2 H2 H2H2 H2 H2 H2 H2 H2 H2 H2
H2 H2 H2 H2 H2 H2 H2 H2 H2 H2H2 H2 H2 H2 H2 H2 H2 H2
H2 H2 H2 H2 H2 H2 H2 H2 H2 H2H2 H2 H2 H2 H2 H2 H2 H2
H2 H2 H2 H2 H2 H2 H2 H2 H2 H2H2 H2 H2 H2 H2 H2 H2 H2
H2 H2 H2 H2 H2 H2 H2 H2 H2 H2H2 H2 H2 H2 H2 H2 H2 H2
H2 H2 H2 H2 H2 H2 H2 H2 H2 H2H2 H2 H2 H2 H2 H2 H2 H2
H2 H2 H2 H2 H2 H2 H2 H2 H2 H2H2 H2 H2 H2 H2 H2 H2 H2
H2 H2 H2 H2 H2 H2 H2 H2 H2 H2H2 H2 H2 H2 H2 H2 H2 H2
H2 H2 H2 H2 H2 H2 H2 H2 H2 H2H2 H2 H2 H2 H2 H2 H2 H2
H2 H2 H2 H2 H2 H2 H2 H2 H2 H2H2 H2 H2 H2 H2 H2 H2 H2
H2 H2 H2 H2 H2 H2 H2 H2 H2 H2H2 H2 H2 H2 H2 H2 H2 H2
H2 H2 H2 H2 H2 H2 H2 H2 H2 H2H2 H2 H2 H2 H2 H2 H2 H2
H2 H2 H2 H2 H2 H2 H2 H2 H2
H2 H2 H2 H2 H2 H2 H2 H2 H2 H2H2 H2 H2 H2 H2 H2 H2 H2
H2
H2
H2
H2
H2
H2
H2
H2
H2
H2
H2
H2
H2
H2
H2
(hydrogen use)“Requires low-carbon hydrogen production at scale from advanced methane reformation, as well as some electrolysis. Will also require hydrogen gas grids, or alternative transportation infrastructure and
development of CCS infrastructure.”
Inte
grat
ed E
nerg
y S
yste
m R
oadm
ap |
Sec
tion
4
Inte
grat
ed E
nerg
y S
yste
m R
oadm
ap |
Sec
tion
4
188 189
Figure 4.6: Pathway to Further Ambition 2050 targets
Oil and gas productionProduction from the UKCS is declining but will still help to meet the UK’s energy and petrochemical needs. New technology deployment will still be required to ensure efficiency and low carbon operations
• The forecast is based on the OGUK Roadmap 2035 oil and gas production forecast
• This forecasts production out to 2035 and assumes the UK will produce 1 mmboe/d of oil and gas in 2035
• 2035-2050 production has been extrapolated based on the 2020-2035 trend
• The production has been split into oil and gas production using the OGA oil and gas production split out to 2024
• This assumes 57% of production is oil, 36% is gas and 6% is NGLs
Offshore renewable capacityThere is a strong pipeline of offshore wind projects over the next decade. After 2030 fixed-bottom deployment will grown steadiliy while floating wind growth picks up
• The forecast is based on Wood Mackenzie’s assumptions of fixed-bottom and floating capacity deployment
• Most of future fixed-bottom capacity is expected to be in England, Wales and Northern Irish waters whereas the majority of floating wind capacity is expected to be in Scottish waters
• It includes known capacity deployment awarded through previous auction rounds
• It also accounts for announced capacity to be awarded in planned auction rounds
• The fixed-bottom vs floating split is based on capacity announcements as part of future auction rounds
Hydrogen productionBlue hydrogen creates the foundation for the low-carbon hydrogen industry. The steep rise in capacity growth will require a similar ramp up in CO2 capture and storage capacity
• The CCC 2050 hydrogen target is made up of 225 TWh from blue hydrogen and 44 TWh from green hydrogen
• 30-60 SMR plants would be needed to achieve the blue hydrogen target: this equates to an average plant size of 5 TWh
• We assume blue hydrogen will be developed first, both as new builds and as conversion of grey hydrogen facilities as CCUS develops
• Capture rates at blue hydrogen projects are expected to be ~50% in the short term and reach upwards of 90% after 2035
• Green hydrogen deployment is assumed to be gradual as new turbines are built; the Dolphyn project model240 was used as an analogue for future green hydrogen projects
H2
CCUS capacityInvestment in capture, transport and storage infrastructure is needed now to ensure blue hydrogen production can ramp up. A steep increase in capacity is needed to reach the CCC target
• The forecast includes existing CCUS projects and their expected capacities, such as the Acorn project, Net Zero Teesside and H2H Saltend project
• We assume these projects are operational by 2030, as per the CCC’s recommendation
• Other CCUS projects are expected to be developed at industrials hubs such as the wider Humberside area, Merseyside and South Wales but the storage potential of these projects is unknown and so they are included in the unknown category
• Capture and storage capacity is assumed to grow in line with blue hydrogen production
Oil Gas
2020 2050
mm
boe/
d
2025 2030 2035 2040 20450.0
0.5
1.0
1.5
2.0
Floating Fixed-bottom
2020 2050
GW
2025 2030 2035 2040 20450
25
50
75
100
2020 2050
TWh
2025 2030 2035 2040 20450
50
100
150
200
250
300
Blue Green Grey
2020 2050
MtC
O2e
/yr
2025 2030 2035 2040 20450
50
100
150
200
Projects CCC forecast
Source: Wood Mackenzie, CCC
Source: Wood Mackenzie, CCC
Source: Wood Mackenzie, OGUK
Source: Wood Mackenzie, CCC
Inte
grat
ed E
nerg
y S
yste
m R
oadm
ap |
Sec
tion
4
Inte
grat
ed E
nerg
y S
yste
m R
oadm
ap |
Sec
tion
4
190 191
Benefits to the UK: Economic impact of achieving net zero targets5
5.1: Introduction to input-output analysisMeeting the CCC’s Further Ambition target through the scaling up of net zero technologies on the UKCS - identified in this report’s Closing the Gap to 2050 Technologies section - creates a significant economic opportunity for the UK. An input-output analysis was conducted to measure the impact these technology sectors (oil and gas, offshore renewables, hydrogen and CCUS) and their related industries could have on the UK economy out to 2050.
Further details regarding the methodology and assumptions are included in the appendix.
Ben
efit
s to
the
UK
: Eco
nom
ic im
pact
of t
he R
oadm
ap |
Sec
tion
5
Ben
efit
s to
the
UK
: Eco
nom
ic im
pact
of t
he R
oadm
ap |
Sec
tion
5
195194
5.2: Sector outlook Oil and gasHydrocarbon production from the UKCS peaked in 1999, however the oil and gas industry will continue to play a major role in the UK economy over the next 30 years. The industry could have a total economic impact of £900 billion from direct, indirect and induced effects on the economy between now and 2050.
Figure 5.1: Direct, indirect and induced impact of the oil and gas industry (in specific years)
Although the majority of future investment will be traditional capex at greenfield and brownfield developments, investment in carbon reduction technologies will be significant in order to meet net zero targets. Capex related to decarbonisation technologies can be high, but that needs to be balanced against the long term opex reductions from improved efficiency, increased uptime and lower carbon tax payments. Investment choices to reduce the carbon intensity of production will ultimately depend on factors such as:
• Regulatory and fiscal considerations• Development maturity• Remaining life of onstream fields• Platform system designs
Employment levels within the oil and gas industry are expected to fall as production declines and facilities cease operations, naturally reducing capacity. Technological advances in digitalisation and subsea operations will also mean that fewer personnel will be required offshore. As that happens, there is potential for people to transition to other industries in the energy value chain such as renewables, hydrogen and CCUS. A range of transferrable skills and knowledge – particularly in geosciences, engineering and energy systems –as well as the crossover locations of energy and industrial hubs, will facilitate this.
£35 billion
Total economic impact
Employment
2020 20502035
246,000
£28 billion £18 billion
121,000 57,000
Oil and gas industry total 2020-2050 economic impact: £900 billion
Box 5.1: Examples of offshore decarbonisation technology costs and potential benefits
• Electrifying a cluster of fields with a 200MW power demand would cost in the region of £1.1 billion. Although unlikely to offset the upfront capex, increased revenue from gas previously used for powering a platform is one of benefits of platform electrification: approximately 1m3 of additional sales gas becomes available per 2.3kg of CO2 saved204.
• Installing methane leak detection and repair (LDAR) would cost between £120,000 and £200,000 in upfront capex and a further £70,000 to £90,000 per site per year but could save up to £4 million in tax if methane emissions were included under carbon tax rules. Methane emissions at UK fields can be as high as 10,000 tonnes per year359 and could be taxed at up to £448 per tonne (28 times the current CO2 tax rate due to methane’s higher global warming potential)360 under the European emissions trading system (ETS).
Source: Wood Mackenzie
Ben
efit
s to
the
UK
: Eco
nom
ic im
pact
of t
he R
oadm
ap |
Sec
tion
5
Ben
efit
s to
the
UK
: Eco
nom
ic im
pact
of t
he R
oadm
ap |
Sec
tion
5
196 197
Risks and uncertainties
Current OGUK forecasts production from existing fields of 271 mmboe in 2035, equivalent to approximately 30% of total demand. Roadmap 2035361 targets the UKCS meeting 50% of UK oil and gas demand which will therefore require continued exploration and development activity.
Additionally, for exploration and production to align with a net zero UKCS, the industry will need to invest in retrofitting and designing new low-carbon operations. Traditional capital investment will also need to support new and existing developments. Low oil prices and volatile market conditions and budgetary constraints could slow investment in emissions abatement. However, investor pressure and the regulatory environment could help to counteract this and sustain a focus on emissions reductions.
The high costs associated with certain technologies and the often complex ownership structures of oil and gas assets mean that concerted industry effort is required to ensure deployment of new technologies that will help the UKCS play a role in meeting net zero targets. This is especially true for major projects such as platform electrification, where the cost could be spread through a consortium approach with shared infrastructure and development costs.
Upside potential
The UK oil and gas industry exports approximately £12 billion of goods and services annually and aims to increase this to £20 billion as part of the Roadmap 2035361. Investing locally in the innovation and manufacturing of decarbonising technologies now would give the UK a first-mover advantage: as other oil and gas basins around the world start to decarbonise, that could boost the industry’s export value.
Figure 5.2: Direct, indirect and induced impact of the offshore renewables industry (in specific years)
£8 billion
Total economic impact
Employment
2020 20502035
21,000
£18 billion £32 billion
99,000 147,000
Offshore renewables industry total 2020-2050 economic impact: £600 billion
Offshore renewablesOffshore wind will be the biggest economic contributor to the offshore renewable industry, with a potential economic impact of £600 billion between now and 2050. The offshore wind industry’s contribution to the UK economy is however subject to investment in new wind farms. Progress in the next decade will be driven by the build out of capacity that has been awarded in recent auctions. We assume a steady investment profile beyond that to reflect the necessary capacity additions that will be needed to reach the CCC’s 75GW offshore wind target. Investment will also be driven by continued unit (per MW) cost reductions for both fixed and floating wind as power ratings (power produced per turbine)
Source: Wood Mackenzie
and capacity factors increase. Floating and fixed-bottom costs are expected to reduce by up to 60% and 70% respectively by 2050 (see figure 5.3), and units costs for floating wind will get close to those of fixed-bottom by the 2040s362. Overall, floating wind is expected to make up a small proportion of installed capacity and total spend.
The economic impact of the offshore wind industry is also influenced by the level of UK content within offshore wind projects. The offshore wind sector currently has an average UK content of 50%12. The Offshore Wind Sector Deal12 aims to increase this to 60% by 2030 and we expect this to continue to increase out to 2050, especially if a local floating wind supply chain is developed.
Ben
efit
s to
the
UK
: Eco
nom
ic im
pact
of t
he R
oadm
ap |
Sec
tion
5
Ben
efit
s to
the
UK
: Eco
nom
ic im
pact
of t
he R
oadm
ap |
Sec
tion
5
198 199
The profitability of the offshore wind sector is highly dependent on the capture price achieved through the sale of wind power. The capture price is dependent on the future power mix: the level and price of gas generated power and the growth of hydrogen produced power are important. Any pricing agreements made with the government during auctions rounds will ultimately dictate the price achieved by wind developers.
The offshore renewable industry has the potential to support nearly 150,000 (direct, indirect and induced) jobs by 2050, and will overtake the oil and gas sector as the largest UKCS employer in the late 2030s. While the offshore renewable industry is relatively ‘employee light’ as day-to-day operations are not labour intensive, increased renewable power is expected to create tens of thousands of new indirect jobs. Employment will be created in the electricity industry, in manufacturing during project development and construction, and through the growth of local supply chains. Even though the UK has the largest deployed offshore wind capacity in the world and several domestic manufacturing facilities363, a large proportion of renewable technology is still imported. The Offshore Wind Sector Deal aims to
generate more economic benefit by reducing the reliance on imports, increasing UK content to 60% by 2030, and creating more than 25,000 direct jobs by 2030364. Alongside capacity build out, the development of the domestic supply chain will be the main driver of increased employment in offshore wind and related industries.
Risks and uncertainties
Although the offshore wind project pipeline is relatively secure to 2030, the timing and scale of buildout is still uncertain after that. New auctions will need to be held in addition to those already planned and market conditions will need to remain favourable for bid rates to remain as high as they have been in past auction rounds.
Government subsidies may still be required to ensure future projects go ahead, especially in the case of floating wind projects. Although some developers are considering the merchant route to market – the sale of electricity directly to distributors at a spot price - the feasibility of that business model for offshore wind is still risky. The level of future government subsidies is therefore a key uncertainty.
Figure 5.3: Fixed bottom and floating wind unit cost reductions (compared to 2020 costs)
The proportion of fixed-bottom and floating capacity is also uncertain as the development of floating projects will be driven by unit cost reductions. The commercialisation of floating wind needs capacity growth to drive cost reduction, however scale, cost reduction and a local supply chain are needed for governments to allocate capacity to floating wind.
Upside potential
The demand for renewable energy across Europe is increasing as new policies, such as the European Green Deal, are developed, and as the green hydrogen economy grows. The offshore wind sector accounted for £0.5 billion of exports in 2018365 with the UK exporting renewable (onshore and offshore wind and marine energy) products and services to 40 countries366. Additionally, the UK can directly export renewable power to mainland Europe via interconnectors to France, the Netherlands and to Belgium (see figure 2.18). Plans to build new interconnectors to Norway, Denmark, Germany and France will increase the amount of renewable power the UK can export and the growth of domestic supply chains will allow more UK products and services to be exported globally.
The UK is currently in the unique position of having the only operational floating wind farm in the world, however it does not have a well-developed floating wind supply base. Developing floating wind expertise and supply chains locally could allow the UK to become a key exporter of these technologies and knowledge. The technical deployment potential of floating wind is virtually unlimited: moving quickly in this space could allow the UK to become the go-to for floating wind developers and manufacturers and to serve a global market367. This could significantly benefit the UK economy, creating jobs, skills and expertise and technology that can be exported.
Although wind has the biggest potential in the UK’s offshore renewables sector, the growth of other technologies including wave and tidal have economic potential but not on the same trajectory as wind. These technologies are not as scalable or as mature as wind, but they are continuing to develop and will support employment and supply chains in coastal areas. The levelised cost of electricity for tidal energy is currently around £300/MWh. This could reduce by 70% to £90/MWh if capacity were to increase to 1GW368.
Figure 5.4: Global offshore wind 2028 forecast and potential floating wind sites
Floating Fixed-bottom
2020 2050
2020
uni
t cos
ts
2030 2040
-70%
-60%
-50%
-40%
-30%
-20%
-10%
Uni
t cos
t red
uctio
n (c
ompa
red
to 2
020
cost
s) %
≥10GW
Offshore wind grid-connected capacity, 2019-2028
5-9.99GW
1-4.99GW
100-999MW
1-99MW
0MW
Potential areas forfloatingwind
Areas where new commercial floating wind pipeline will emerge in the short-term
Potential areas for floating wind build-out where fixed-bottom is not feasible
Potential areas for floating wind build-out by 2030
Source: Wood Mackenzie
Source: Wood Mackenzie2020-80%
0%
Ben
efit
s to
the
UK
: Eco
nom
ic im
pact
of t
he R
oadm
ap |
Sec
tion
5
Ben
efit
s to
the
UK
: Eco
nom
ic im
pact
of t
he R
oadm
ap |
Sec
tion
5
200 201
HydrogenThe growth in demand for hydrogen over the next 30 years will be driven by its use as a low carbon alternative in heavy transport and a wide range of hard-to-abate sectors such as heating and heavy industry. Employment is expected to increase in line with revenue369 and the projected growth of the blue and green hydrogen industries could create over 90,000 new jobs within research and development, manufacturing, installation and operations. However, the economic impact potential from the development of blue and green hydrogen industries extends beyond employment: its widespread potential use, the need to develop new infrastructure and its interdependence with other related industries, will all add up. One of the main contributing factors to the large economic
impact that could be generated by the hydrogen industry are the high operating costs associated with the purchase of feedstock – gas in the case of blue hydrogen and electricity and water for green hydrogen – as well as having to pay for CO2 storage and transport (in the case of blue hydrogen). While those are added expenses for hydrogen producers, the gas, electricity and renewables and CCUS industries will gain revenue, with a positive economic impact across the UK economy.
The level of investment associated with hydrogen production is driven by production method. The main capital investment for blue hydrogen relates to the installation of CO2 capture equipment, and the operating costs are mainly related to transporting and storing captured CO2 and the
feedstock cost of the natural gas (see Closing the Gap to 2050 Technologies – Hydrogen for more details). Associated operating costs are expected to increase in the long term as carbon taxes and the price of natural gas increase.
Green hydrogen’s primary opex are feedstock costs for water supply and electricity. As the amount of available renewable energy increases, we expect the electricity costs to decrease. Electrolyser capex costs for green hydrogen production are high as most parts of the electrolyser are made manually. Manufacturing automation will be a key cost-reduction driver.
Both green and blue hydrogen will need to be transported to demand centres– industrial hubs or hydrogen networks –and adequately stored. Domestic gas grids will also need to be adapted or developed to allow hydrogen to be mixed with, or replace, natural gas for domestic use. The infrastructure and facility development that is required will have a further economic impact.
Risks and uncertainties
Demand for hydrogen in the UK is currently very limited. The CCC recommends developing a hydrogen economy in which hydrogen is used in home heating, transport, industry and energy generation; however, developing the supply and demand to scale and in unison will require careful planning and coordinated investment. Several projects, such as Hynet NorthWest, are already investigating the development of hydrogen economies at a regional scale. These projects are still in the feasibility stage and need further funding and approval. Without a major growth in hydrogen demand across the economy, neither the scale of hydrogen production, nor the economic impact of it as modelled in this study, will materialise.
Both blue and green hydrogen are not currently cost competitive when compared to grey hydrogen and other forms of energy370. For production to ramp up, costs need to come down. Either government support or a suitable carbon price are likely to be needed to develop and scale hydrogen technologies. Additionally, increased offshore wind
capacity, developed at a decreasing cost, would improve the economics of green hydrogen.The development of blue hydrogen is dependent on the construction of carbon capture, transportation and use or storage infrastructure that will allow the CO2 created during the production process to be abated. If the CCUS industry were to develop more slowly than forecast, this would jeopardise the growth in blue hydrogen production that is required to meet the CCC’s targets.
If hydrogen is cheaper to import than to produce domestically, the industry’s development could have fewer benefits for the UK economy and employment than what we have modelled in this study. Other countries such as Australia are already utilising their sizeable renewables potential to develop green hydrogen production and if it or other regions with low cost renewable energy, can supply hydrogen at a lower cost than the domestic market, that will clearly impact the scale of the local industry and supply chain.
Upside potential
If large scale competitive hydrogen production succeeds, then the UK could become a net exporter of blue and green hydrogen to other countries. This could be either in the form of hydrogen or converted and shipped as ammonia, methanol or similar chemicals. Global and regional demand for hydrogen products is set to grow. Within the EU, the hydrogen roadmap outlines the significant potential for the hydrogen economy, suggesting that investments of over €52 billion by 2030371 will be made in the industry. The UK could also become a centre for international industries looking to decarbonise, such as the shipping sector, through offshore fuelling hubs.
There are already more than 100 companies and over 35 academic and contract research groups in the UK372 that have been internationally recognised for their development and research on hydrogen production, supply and storage. If the UK continues to develop its domestic hydrogen base and expertise, it has the opportunity to become a centre of excellence for hydrogen production, and a chance to export knowledge, skills and innovative technologies globally.
Figure 5.5: Direct, indirect and induced impact of the hydrogen industry (in specific years)
£2 billion
Total economic impact
Employment
2020 20502035
7,000
£21 billion £61 billion
37,000 100,000
Hydrogen industry total 2020-2050 economic impact: £800 billion
Source: Wood Mackenzie
Ben
efit
s to
the
UK
: Eco
nom
ic im
pact
of t
he R
oadm
ap |
Sec
tion
5
Ben
efit
s to
the
UK
: Eco
nom
ic im
pact
of t
he R
oadm
ap |
Sec
tion
5
202 203
CCUSCCUS remains a nascent industry in the UK. It will require significant capital investment in a relatively short period to develop the necessary capture, transport and storage infrastructure to meet the CCC target. The highest capital costs are associated with the capture technology which will need to be installed at all large- scale emission sites. Capture costs make up the largest proportion of CCUS capex. Currently, capture costs are around £100 per tonne of CO2 captured however these costs are expected to significantly reduce by 2050 to less than £50 per tonne of CO2. The costs associated with CO2 transportation will vary depending on distance, location (onshore vs offshore) and if a pipeline is a newbuild or has been retrofitted. To reduce costs, we assume the majority of carbon will be captured at industrial sites and transported to offshore storage sites in regional proximity.
By 2050, the CCUS industry could create up to 15,000 new jobs (direct, indirect and induced). Most of these jobs are expected to be created during the manufacturing and construction phase of projects. Once a CCUS project is in operation, it is expected to be relatively ‘labour light’373.
A viable business model for the CCUS industry is still unclear as there is currently limited economic incentive to store CO2. For example, the current European Emission Trading System (ETS) carbon price is insufficient to support the case for CCUS investment374. Government intervention is required to kick start the CCUS industry and there are multiple options for doing so, as outlined in table 5.1.
For the purposes of this report, we assume CO2 producers will invest in CO2 capture technologies and then pay a fee to have CO2 transported and stored by a specialist CCS operator.
Figure 5.6: Direct, indirect and induced impact of the CCUS industry (in specific years)
<£1 million
Total economic impact
Employment
2020 20502035
<500
£6 billion £15 billion
15,000 15,000
CCUS industry total 2020-2050 economic impact: £200 billion
Table 5.1: Potential government policies for incentivising CCUS growth
Governments provide tax credits for every tonne of CO2 stored. For example, the 45Q tax credit scheme in the US allows industrial manufacturers to earn up to $50 per tonne of CO2 that is permanently stored and up to $35 per tonne CO2 that is used for EOR375.
A tax credit is available for capturing emissions. For example, California’s Low Carbon Fuel Standard CCS protocol allows CCS projects to be used to offset emissions associated with the production of transport fuels and therefore earn credits which can be worth up to US$190 per tonne of CO2 captured376.
Governments introduce policy that requires fossil fuel suppliers to offset a proportion of the scope 3 emissions associated with the end use of their products. For example, “a carbon take-back scheme” was proposed by UK academics in 2015406 and would oblige fossil fuel producers to prove they have stored, or paid a third party to store, a certain proportion of CO2 emissions associated with the end use of their carbon related products. The proportion of emissions that need to be offset would increase, eventually reaching 100%.
A carbon tax is introduced that makes it more cost effective for CO2 producers to invest in capture, transport and storage equipment than pay the tax.
Governments introduce CfD agreements which guarantee thermal power or industrial players that install carbon capture technology a guaranteed price for, respectively, electricity sales or carbon abated. These companies then pay carbon transport and storage operators a regulated fee for transporting and permanently sequestering the carbon.
Source: Wood Mackenzie
Ben
efit
s to
the
UK
: Eco
nom
ic im
pact
of t
he R
oadm
ap |
Sec
tion
5
Ben
efit
s to
the
UK
: Eco
nom
ic im
pact
of t
he R
oadm
ap |
Sec
tion
5
204 205
Risks and uncertainties
The high upfront capital costs and the lack of a clear business model mean that the CCUS industry needs more support if it is to develop. Several CCUS projects received UK government funding in the early 2010s but the projects did not progress past pilot stages after the funding was stopped. New CCUS projects, such as Acorn and Teesside, are currently progressing through the concept phase and in the 2020 budget, the government announced £800 million of funding for CCUS projects.
The blue hydrogen industry is one of the key cornerstones for CCUS development. If the blue hydrogen industry does not scale as expected, then it will remove a key driver to develop CCUS.
Current CCUS projects are planning to take advantage of carbon sources and underground sinks that are geographically close together to reduce transport costs. However, this will not be the case for all CO2 emissions; cost effective storage or utilisation methods will be needed for highly emissive industrial sites that are not near storage sites.
Upside potential
The CCC estimates that the global CCUS industry could be worth around £100 billion by 2050377. The UK’s storage potential is enough to sequester nearly 200 years of CO2 emissions378 – based on the UK’s current emission rate – and is therefore in a position to set itself up as a CO2 hub, storing CO2 from other countries at a fee. Carbon offsetting is growing as a way for companies to achieve net zero targets and it is estimated that, in 2018, 100 Mt CO2 was traded, creating a global market worth nearly US$300 million379. If the UK CCUS industry develops ahead of other countries, it could be in a prime position to take advantage of the global carbon offset demand.
As well as storing CO2, the UK could build on its utilisation industries. Developing a use for captured CO2 not only has a direct economic benefit through the sale of the new product, but could also lead to the development of another new export industry.
Over 200 CCUS academics are working across numerous UK institutes to develop world-class CCUS research380. Building on this existing research and innovation positions the UK to become a world leader in CCUS, exporting knowledge and technologies to further benefit the UK’s economy.
Total economic impactFigure 5.7: Total economic impact in specific years (based on direct, indirect and induced effects)
Oil and Gas Offshore renewables Hydrogen CCUS
£18 billion £32 billion £61 billion £15 billion
2050£125 billion
£24 billion £23 billion £44 billion £8 billion
2040£100 billion
£33 billion £17 billion £5 billion £5 billion
2030£60 billion
£35 billion £8 billion £2 billion <£1 million
2020£44 billion
Source: Wood Mackenzie
Ben
efit
s to
the
UK
: Eco
nom
ic im
pact
of t
he R
oadm
ap |
Sec
tion
5
Ben
efit
s to
the
UK
: Eco
nom
ic im
pact
of t
he R
oadm
ap |
Sec
tion
5
206 207
5.3: UK impact summaryInvesting in low-carbon technologies and establishing an integrated energy network will be pivotal to achieving the net zero 2050 target for both the UKCS and the wider economy. As this analysis demonstrates, the natural decline of the oil and gas sector will be more than offset by the growth in renewables, hydrogen and CCUS. This transition will drive significant economic growth through the expansion of the energy sector and development of an integrated energy network across the UKCS. The direct, indirect and induced effects of this could have a total economic impact of £2.5 trillion on the UK economy between now and 2050, as well as create over 200,000 new jobs. Employment across the oil and gas, offshore renewables, hydrogen and CCUS industry would add up to more than 300,000 in 2050.
There is also huge export potential for the low-carbon industries, particularly within Europe. The European Commission’s “A Clean Planet for all” strategy381 highlights the importance of innovative technologies in renewable energy, CCUS, energy storage and substitute products in energy intensive industries in meeting the European Green Deal’s net zero GHG emissions by the 2050 target382. Over €10 billion - money raised through the sale of EU ETS allowances - is to be invested in innovative technologies by 2030, demonstrating the EU’s commitment to these low carbon technology industries. The first of the annual funding opportunities launched in July 2020 and will make £1 billion available to large-scale renewable, blue/green hydrogen, energy storage and CCUS projects.
These commitments indicate the potential scale of the market in Europe and associated export opportunities for the renewables, hydrogen and CCUS industries. Using the ratio of the current oil and gas export value and total domestic economic impact as a proxy, the export potential across the offshore renewables, hydrogen and CCUS industries could be worth £36 billion – on top of the domestic economic impact – in 2050. Export of renewable energy, hydrogen and CCUS products and expertise could outstrip that of oil and gas as European policy encourages the growth of these industries and interconnectedness between countries (see table 5.2).
Table 5.2: European opportunities
Renewables
The EU aims to increase renewable’s share of total energy consumption to 32% by 2030383. Although it has been suggested more renewable power (primarily solar) could be imported to Europe from North Africa384, logistically this is likely to only serve southern European countries. That leaves an opportunity for the UK to export renewable power to northern European states using both existing and planned interconnectors. To meet the EU hydrogen production targets, more than 30,000 TWh of renewable electricity would be required385 – more than all the electricity that is currently produced globally386 . That has the potential to be significant new demand sector that UK offshore renewable power could supply.
H2
Hydrogen
Under the “Hydrogen Roadmap Europe”, Hydrogen could meet 24% of total energy demand in 2050, equivalent to ~2,250 TWh of energy. That would create an estimated €130 billion industry in Europe by 2030, reaching €820 billion by 2050387. Many European countries have already set up national hydrogen policies. For example, the Portuguese government is targeting a €7 billion investment in green hydrogen projects by 2030, underpinning its goal to reach carbon neutrality by 2050388.
CCUS
The European Commission considers CCUS as the only option to reduce large scale emissions from industrial processes and its role is acknowledged in the 2030 climate and energy policy framework389. CCUS projects that link energy systems of different EU countries – projects of common interest (PCIs) – are being encouraged through favourable funding opportunities and reduced regulatory barriers390. The latest list of PCIs, released in 2019, included five cross-border carbon dioxide network projects. The UK based Acorn project was one of these, as was the Norwegian Northern Lights project, which aims to create a CO2 cross-border transport connection project: CO2 would be captured from several countries including the UK and shipped to a storage site on the Norwegian continental shelf391.
Ben
efit
s to
the
UK
: Eco
nom
ic im
pact
of t
he R
oadm
ap |
Sec
tion
5
Ben
efit
s to
the
UK
: Eco
nom
ic im
pact
of t
he R
oadm
ap |
Sec
tion
5
208 209
Capital investmentTo achieve the targets set out in the Integrated Energy System Roadmap – meeting the CCC Targets section of this report, a total of £270 billion of capex will need to be invested in UK industries between 2020 and 2050. Over the next 15 years, direct investment will be particularly important to ensure that the CCUS and low-carbon hydrogen industries take off. The UK government has allocated funding to initiatives in these industries including £800 million to CCUS and £28 million to low-carbon hydrogen projects392, although a further £3.5 billion will be required over the next 10 years. Early and committed investment is one of the most significant risks in reaching the CCC’s targets. Both hydrogen and CCUS will see most capital investment from 2035 onwards, each requiring between £70 and £100 billion of total capex to reach their respective 2050 targets. If UK industries move early, they could ensure they capture well over half of this investment.
Over the next 15 years, the offshore wind and oil and gas industries will each require £75 billion in capital investment to reach their respective targets. Approximately half of this is expected to be spent in the UK due to the current local content levels in each industry. Growing the local supply chains will ensure a greater proportion of future capex is captured by UK industries. It is assumed the hydrogen and CCUS industries will develop strong local supply chains and so a larger proportion of capex spend will feed into the UK economy.
Capital investmentFigure 5.8: Forecast capital investment (UK content) for specific years
Oil and Gas Offshore renewables Hydrogen CCUS
£2 billion <£1 billion £4 billion £5 billion
2050£11 billion
£2 billion £2 billion £4 billion £3 billion
2040£10 billion
£3 billion £1 billion <£1 billion £1 billion
2030£5 billion
£5 billion £3 billion <£1 billion <£1 billion
2020£8 billion
Source: Wood Mackenzie
Ben
efit
s to
the
UK
: Eco
nom
ic im
pact
of t
he R
oadm
ap |
Sec
tion
5
Ben
efit
s to
the
UK
: Eco
nom
ic im
pact
of t
he R
oadm
ap |
Sec
tion
5
210 211
RevenueThe investment in net zero technologies and an integrated energy system has the potential to generate £36 billion in revenue in 2050 through the domestic sale of products and services – more than double the total revenue generated across these industries today. The development of a low-carbon hydrogen industry and an increase in offshore renewable power generation will be the main drivers of this growth. Nevertheless, a wide range of stakeholders will need to manage the interdependencies across all four low-carbon industries that will be created by the integrated nature of the energy system. Most importantly, government funding and policy and regulatory changes will be required.
RevenueFigure 5.9: Forecast revenue in specific years
Oil and Gas Offshore renewables Hydrogen CCUS
£15 billion £1 billion <£1 billion <£1 million
2020£17 billion
£9 billion £11 billion £14 billion £4 billion
2050£36 billion
£12 billion £7 billion £12 billion £2 billion
2040£32 billion
£16 billion £5 billion £2 billion £2 billion
2030£24 billion
Source: Wood Mackenzie
Ben
efit
s to
the
UK
: Eco
nom
ic im
pact
of t
he R
oadm
ap |
Sec
tion
5
Ben
efit
s to
the
UK
: Eco
nom
ic im
pact
of t
he R
oadm
ap |
Sec
tion
5
212 213
EmploymentAs well as economic impact, over 200,000 new direct, indirect and induced jobs could be created across the UK through the growth of offshore renewables, hydrogen and CCUS. That will more than offset the decline in employment in the oil and gas industry as there will be more than 300,000 jobs across all these sectors by 2050. These new jobs are likely to be created in industrial areas, where traditional industries are in decline, and in North Sea coastal cities, where oil and gas industries make up a large part of the economy. Global export of products and services creates a portion of direct and indirect employment in the oil and gas industry, whereas the employment forecasts shown here for the offshore renewables, hydrogen and CCUS industries only reflect domestic production and consumption. If these industries were to realise the potential export opportunities, as we saw evolve in the oil and gas sector, this could further increase direct and indirect employment numbers.
EmploymentFigure 5.10: Forecast direct, indirect and induced employment in specific years
Oil and Gas Offshore renewables Hydrogen CCUS
245,000 20,000 5000 <1000
2020275,000
95,000 110,000 85,000 15,000
2040305,000
Direct Indirect Induced = 10,000 employees (rounded to the nearest 10,000)
55,000 150,000 100,000 15,000
2050320,000
150,000 90,000 10,000 15,000
2030270,000
Source: Wood Mackenzie
Ben
efit
s to
the
UK
: Eco
nom
ic im
pact
of t
he R
oadm
ap |
Sec
tion
5
Ben
efit
s to
the
UK
: Eco
nom
ic im
pact
of t
he R
oadm
ap |
Sec
tion
5
214 215
Unlocking the Potential6
Key technologies, timelines and system dependencies
2020 2030 2040 2050
Subsea technologies
Subsea technologies
Advanced methane leak detection
Platform electrification
Flaring mitigation
Bottom-fixed wind
Floating wind
Other renewables (e.g. marine)
Offshore energy storage
Blue Hydrogen
Green Hydrogen
Hydrogen storage/ transport
Fuel cells
Hydrogen turbines
CO2 capture
CO2 transportation
CO2 storage
CO2 utilisation
A
B
C
D
6.1: Technology gap priorities for unlocking the UKCS’ potential
Current level of development versus
CCC 2050 targets
Oil and gas
CAGR: -3%
Oil and gas production*
Renewables
CAGR: 7%
Installed offshore wind capacity
H2
Hydrogen
CAGR: 8%
Total hydrogen production
CCUS
CAGR: 55%
CO2 capture and storage potential
1.6 mmboed
0.7 mmboed
10.5 GW
75 GW
27 TWh
270 TWh
<0.5 MtCO2e/yr
176 MtCO2e/yr
Potential economic impact
Innovation gap prioritiesTotal capex
required between 2020
and 2050**
Total domestic economic
impact between 2020 and 2050
UK employment in 2050
(direct, indorect and induced)
Short term: build out of electrification infrastructure (subsea cables and HV substations)
Short term: retrofit gas turbines to run on ammonia-hydrogen blend where possible
Short-mid term: design of subsea equipment that can be re-used and integrated with renewables
£123bn £0.9tr 57,000
Short term: build out of transmission systems, i.e. HVDC cables connecting floating wind farms to the shore
Short term: standardisation of floating foundation designs
Mid-long term: improve efficiency of nascent technologies (AES and marine energy)
£100bn £0.6tr 147,000
Short term: development of integrated desalination and electrolysis units to couple with offshore wind turbines
Short term: improve yield and CO2 capture efficiency of blue hydrogen reactors
Mid-long term: development of hydrogen pipeline (develop repurposing practises) and storage facilities (i.e. underground storage)
£120bn £0.8tr 100,000
Short term: improve efficiency of capture technologies (i.e. solvents, sorbents, membranes etc.)
Mid-long term: improve efficiency of CO2 conversion processes
Long term: scale-up and deployment of direct air capture
£90bn £0.2tr 15,000
*Based on Roadmap 2035 extrapolated to 2050
** Total capex required, i.e. includes UK content capex and capex spent internationally
Green hydrogenA BC D
Platform electrification
Blue hydrogen Hydrogen value chain
Source: Wood Mackenzie, Lux Research
UKCS integrated energy system interdependencies
Unl
ocki
ng th
e P
oten
tial
| S
ectio
n 6
Unl
ocki
ng th
e P
oten
tial
| S
ectio
n 6
218 219
6.2: Technology Challenges
Offshore power grid managementIntegrating offshore wind developments with existing and planned offshore oil and gas operational power demand via interconnected infrastructure could enable the critical electrification of oil and gas installations, while at the same
time facilitating stable low-carbon electricity supply to the National Grid. Power grid costs can be shared between oil and gas, wind farm, energy storage and transmission operators. However, to unlock this prize, technological innovation is required at both system and individual technology level.
Short-term challenges Long-term challenges
CCUSWhile coordinated financial and policy support will be necessary to create favourable conditions to kick-start the CCUS industry, reducing the cost of carbon capture, transportation and storage technology will be essential
to ensuring that the costs of implementing CCUS are minimised. Today’s high capex costs associated with the development of CO2 capture, transportation and storage infrastructure offer many opportunities for both evolutionary and disruptive innovation.
Hydrogen innovationFor hydrogen to play a key role in reaching net zero targets, a hydrogen supply chain needs to be in development before 2035. This requires a concerted and coordinated effort to develop economically viable solutions across the
end-to-end hydrogen economy – from production, though transport and storage, to end use. The opportunity to develop blue and green hydrogen production technologies, alongside novel transportation and storage solutions, offers an unparalleled opportunity for the supply chain to seize a position at the vanguard of this nascent international market.
In order to stimulate demand, there is a need for clear incentives for low-carbon hydrogen in order to develop sufficient demand in onshore industries, including transportation, domestic or industrial heating, or even hydrogen or CO2 derived materials, chemicals and fuels.
DigitalisationA reliable and connected data infrastructure, combined with widespread use of data analytics and control, will be essential for the efficient delivery of low carbon energy from the UKCS. Digital technologies will initially promote
operational and energy efficiency. As an integrated energy system develops, unmanned and autonomous digital facilities within each industry will need to be connected. This requires ensuring data interoperability across the different components in the energy system and strong communication infrastructure. Maintaining the highest possible level of cyber security between assets and operations centres onshore will remain critical tasks in any digital system.
Energy hubsEnergy hubs which combine operation, production, storage and transport of the four energy industries key to the UKCS’ future will be the cornerstones of an integrated energy system. In order for these hubs to be deployed
optimally, innovation is required across all four sectors, for example eliminating methane leaks, reducing the cost of floating wind foundations, optimising blue hydrogen production and better understanding CO2 reservoir behaviour. All infrastructure developed for and around such energy hubs will also need to consider end-of-life, with designs that allow for easy decommissioning or repurposing.
Storage and transportEnergy storage and transport will be crucial to safeguarding the UK’s energy supply. Developing the technology to reliably identify and deliver suitable geological options for long and medium term energy storage will be critical to
ensuring that system costs are minimised. Repurposing the existing offshore infrastructure, and constructing new purpose-built infrastructure, will require innovation in materials, equipment, installation methods and renovation techniques.
Unl
ocki
ng th
e P
oten
tial
| S
ectio
n 6
Unl
ocki
ng th
e P
oten
tial
| S
ectio
n 6
221220
7.1: Appendix
Levelized cost of energy (LCOE) The price per MWh a generator must earn to cover its full life capital and operating costs; the higher the capital and operating costs of a project, the higher the LCOE (£ or $ per MWh)
Strike price An agreed price per MWh paid to a wind generator for delivery of electricity. Wind generators bid a strike price to win capacity contracts with the government; if the actual received for electricity is lower than the strike price the government will pay a ‘top-up’ to the generator: if the actual price is higher than the strike price, the generator pays the ‘extra’ to the government (£ or $ per MWh)
Capture price Refers to the actual price (£ per MWh) a renewables project is likely to receive through the sale of electricity. It is determined by market factors, i.e. the amount of energy entering the system at the time of sale, and the profile of energy output, i.e. when the energy is produced and the electricity demand/price at that time.
Wind costs and prices
Input-output methodology
For each of the technology sectors, relevant inputs - in the form of expenditure and top line revenue - were defined and assigned to the related industries they impact. The overall impact on the UK economy was then calculated using a relevant economic impact multiplier (a Leontief Inverse Multiplier). The impact across the economy will vary for each industry due to the different interdependencies between sectors, i.e. for every £1 million inputted into the extraction of crude petroleum and natural gas industry, there is a total economic impact of £1.7 million through direct, indirect and induced impacts on the economy.
The input-output analysis was based on the 2015 detailed UK input-output analytical table,393 which is consistent with the 2018 editions of the United Kingdom National Accounts Blue Book and United Kingdom Balance of Payments Pink Book. The multipliers from the 2015 input-output table have been modified to show potential change over time and to include type II impacts (induced effects). The compound annual growth rate from 1995-2015 was calculated from previous input-output tables and used to extrapolate future Leontief Inverse multipliers. The additional type II multipliers that measure the induced impact on the economy have been calculated using data released by the Scottish government394 , as the Scottish economy was considered a good analogue for the UK as a whole.
Technology industry inputs are determined by how capital and operating expenditure (capex and opex) is spent, the revenue that is generated through sales of products and services (i.e. the business model), as well as the capacity and growth outlook from the integrated energy system roadmap (which combines the technology roadmap and a pathway to meeting the CCC Further Ambition targets). The impact on the economy is assessed as the direct, indirect and induced economic impact and employment created.
We note that there is much uncertainty in the scale and pace of our outlook, as well as the business model of choice for each technology family – as a result we have highlighted some of the risks and uncertainties.
Input
Capital expenditure
Operational expenditure
Revenue
Growth of technology
Business model
Relevant Industries*
Manufacturing
Construction
Petroleum extraction
Mining support services
Gas: distribution of gaseous fuels
Scientific research and development
services
Impact on economy
Total economic impact
(direct, indirect and induced)
Total employment
(direct, indirect and induced)
Figure 7.1: Representation of input-output model
* Example of relevant industries
Leontief Inverse
Multipliers
222 223
App
enxd
ix |
Febr
uary
202
0
App
enxd
ix |
Febr
uary
202
0
Model input Description Reference
Oil and gas revenue Assumes revenue from the sale of oil and gas. Production forecast is an extrapolation of the OGUK “Roadmap 2035” report extrapolated to 2050. The Wood Mackenzie Q2 2020 oil price assumption has been used which assumes a long-term Brent price of US$50/bbl in 2020 real terms.
Production forecast: OGUK395
Oil/gas price: Wood Mackenzie
Oil and gas expenditure Assumes spend from this industry in the form of capital and operating expenditure. Forecast is based on the OGA 2020-2024 spend extrapolated to 2050 based on production forecast.
Expenditure forecast: OGA396
Offshore wind revenue Assumes revenue from the sale of electricity produced from offshore wind. Electricity (capture) price is based on Wood Mackenzie research.
Capture price forecast: Wood Mackenzie
Offshore wind expenditure
Assumes spend from this industry in form of capital and operating expenditure. This is specific to turbine type (fixed bottom vs floating) and is based on Wood Mackenzie’s forecast of offshore wind capacity growth and cost reductions.
Expenditure forecast: Wood Mackenzie
Hydrogen revenue Assumes revenue from the sale of hydrogen. Price is modelled as £/kg and varies depending on production method. The price of blue hydrogen is assumed to fall from £1.93/kg in 2020 to £1.67/kg in 2050. The price of green hydrogen is assumed to fall from £4.78/kg in 2020 to £1.67/kg in 2050.
Hydrogen price forecast: Lux Research and Wood Mackenzie
Hydrogen expenditure Assumes spend from this industry in the form of capital and operating expenditure. Blue and green hydrogen capital and operating costs were collated in the preparatory work to prepare the Closing the Gap to 2050 Technologies section of this report. We assume up to 7,660km of hydrogen pipelines could be developed, equivalent to the current length of the NTS397.
Expenditure forecast: Lux Research and Wood Mackenzie
CCUS revenue Assumes revenue from the use of transport and storage facilities as a £/per tonne CO2 stored cost. Assumes drop in storage and transport fee from £150/tCO2 in 2020 to £20/tCO2 in 2030.
Transport and storage fee forecast: Lux Research and Wood Mackenzie
CCUS expenditure Assumes spend from this industry in form of capital and operating expenditure. CCUS costs were collated during the Closing the Gap to 2050 Technologies section of this report.
Expenditure forecast: Lux Research and wood Mackenzie
Input-output model: economic assumptions
Model input Description Reference
Oil and gas labour intensity, indirect and induced employment multipliers
Employment/production used to calculate direct, indirect and induced employment forecasts. Based on 2018 data.
Employment and production data: OGUK398
Offshore wind labour intensity
Employment/capacity used to calculate direct employment forecast. Based on 2018 data.
Direct employment data: Office for National Statistics (ONS)399
Capacity data: Wood Mackenzie
Offshore wind indirect employment multiplier
Multiplier applied to direct employment to calculate indirect (type I) employment.
Indirect employment data: ORE catapult and Crown Estate Scotland study400
Offshore wind induced employment multiplier
Multiplier applied to direct employment to calculate induced (type II) employment.
Multiplier: Scottish government394
Hydrogen labour intensity
Employment/revenue used to calculate direct employment forecast.
Labour intensity estimate: UK HFCA369 Production forecast: Integrated Energy System Roadmap - Meeting the CCC Targets section
CCUS labour intensity Employment/storage capacity used to calculate direct employment forecast.
Direct job estimate: Teesside Net Zero401 Capture and storage capacity forecast: Integrated Energy System Roadmap - Meeting the CCC Targets section
Hydrogen/CCUS indirect employment multiplier
Multiplier applied to direct employment to calculate indirect (type I) employment. Gas industry used as an analogue for hydrogen. Mining support services industry used as an analogue for CCUS industry.
Indirect employment multipliers: Office for National Statistics (ONS)402
Hydrogen/CCUS induced employment multiplier
Multiplier applied to direct employment to calculate induced (type II) employment. Gas industry used as an analogue for hydrogen. Mining support services industry used as an analogue for CCUS industry.
Induced employment multipliers: Scottish government394
Input-output model: employment assumptions
224 225
App
enxd
ix |
Febr
uary
202
0
App
enxd
ix |
Febr
uary
202
0
References1 Wood Mackenzie. (2019). United Kingdom upstream summary
2 Oil & Gas UK. (2019). Economic Outlook 2019. [online] Available at: <https://oilandgasuk.cld.bz/Economic-Report-2019> [Accessed 10 February 2020]
3 Hough, D., (2017). UK offshore oil and gas industry. [online] Available at: <https://www.parliament.uk/commons-library> [Accessed 10 February 2020]
4 Hinson, S., Rhodes, C., Dempsey, N., Sutherland, N., Pratt, A., (2018). Uk oil and gas industry. [Online]. Available at: <https://researchbriefings.parliament.uk/ResearchBriefing/Summary/CDP-2018-0088#fullreport> [Accessed 13 February 2020]
5 Statista.com. (2019). United Kingdom (UK) total HMRC tax receipts from fiscal year 2000/01 to fiscal year 2018/19 [Online]. Statista. Available at: <https://www.statista.com/statistics/284298/total-united-kingdom-hmrc-tax-receipts/> [Accessed 17 February 2020]
6 Oil & Gas UK. (2019). Business Outlook 2019. [online] Available at: <https://oilandgasuk.cld.bz/Business-Outlook-2019> [Accessed 10 February 2020]
7 UK Government. (2019). [Online]. Available at: <https://www.gov.uk/government/statistics/government-revenues-from-uk-oil-and-gas-production--2> [Accessed 17 February 2020]
8 Wood Mackenzie. (2019). UK CfD allocation round 3 awards 5.5GW of offshore wind – UK government could receive £2.4 billion from these projects
9 Office for National Statistics. (2018). Low carbon and renewable energy economy, UK:2018. [online] Available at: <https://www.ons.gov.uk/economy/environmentalaccounts/bulletins/finalestimates/2018#turnover-and-employment> [Accessed 17 February 2020]
10 Oil & Gas UK. (2019). Workforce Outlook 2019. [online] Available at: <https://oilandgasuk.cld.bz/Workforce-Report-2019> [Accessed 10 February 2020]
11 Ons.gov.uk. (2019). UK employment data [Online]. Office for National Statistics. Available at: <https://www.ons.gov.uk/employmentandlabourmarket/peopleinwork/employmentandemployeetypes/bulletins/employmentintheuk/september2019> [Accessed 13 February 2020]
12 UK Government. (2020). Offshore wind Sector Deal. [online]. Available at: <https://www.gov.uk/government/publications/offshore-wind-sector-deal/offshore-wind-sector-deal> [Accessed 13 February 2020]
13 Offshore Renewable Energy Catapult. (2019). UK Offshore Wind: Realising the Sector Deal Opportunity. [Online]. Available at: <https://ore.catapult.org.uk/analysisinsight/realising-the-sector-deal-opportunity/> [Accessed 10 February 2020]
14 Whitmarch, M., Canning, C., Ellson, T., Sinclair, V., Thorogood, M., (2019). The UK Offshore Wind Industry: Supply Chain Review [Online]. Available at: <https://www.renewableuk.com/news/436350/The-UK-Offshore-Wind-Industry-Supply-Chain-Review.htm> [Accessed 12 February 2020].
15 Energy & Utility Skills. (2018). Skills and Labour Requirements of the UK Offshore Wind Industry [Online]. Available at: <https://aurawindenergy.com/uploads/publications/Aura-EU-Skills-UK-Offshore-Wind-Skills-Study-Full-Report-October-2018.pdf> [Accessed 13 February 2020]
16 Statista.com. (2019). Employment in the renewable energy sector in the United Kingdom (UK) 2018, by technology [Online]. Statista. Available at: <https://www.statista.com/statistics/690043/renewable-energy-employment-uk/> [Accessed 13 February 2020].
17 Wood Mackenzie. (2020). Energy Market Service: UK data
18 Wood Mackenzie. (2020). Power & Renewables: UK offshore wind data
19 Department for Business, Energy and Industrial Strategy. (2020). Final UK greenhouse gas emissions national statistics [Online]. Available at: <https://data.gov.uk/dataset/9568363e-57e5-4c33-9e00-31dc528fcc5a/final-uk-greenhouse-gas-emissions-national-statistics> [Accessed 13 February 2020]
20 International Energy Agency. (2020). Data and Statistics: data tables [Online]. Available at: <https://www.iea.org/data-and-statistics/data-tables?country=UK&energy=Balances&year=2018> [Accessed 13 February 2020].
21 Maritimefoundation.uk (2018) Editorial: How do we value the oceans? [Online]. Maritime Foundation. Available at:<https://www.maritimefoundation.uk/publications/maritime-2018/ocean-values/> [Accessed 18 February 2020].
22 Oil & Gas UK. (2020). Fisheries [Online]. Available at: <https://oilandgasuk.co.uk/fisheries/> [Accessed 18 February 2020].
23 Oil and Gas Climate Initiative. (2020). [Online]. Available at: <https://oilandgasclimateinitiative.com/climate-investments/> [Accessed 03 March 2020].
24 Renews.biz (2020) Taskforce targets hydrogen growth in the UK homes [Online]. ReNews. Available at: <https://renews.biz/58903/taskforce-targets-hydrogen-growth-in-the-uk/> [Accessed 03 March 2020].
25 Wood Mackenzie. (2020). Upstream Supply Chain – Platform database
26 Wood Mackenzie. (2020). Upstream Supply Chain – Pipeline database
27 Energy technologies institute. (2016). Progressing Development of the UK’s Strategic Carbon Dioxide Storage Resource [Online]. Available at: <https://s3-eu-west-1.amazonaws.com/assets.eti.co.uk/legacyUploads/2016/04/D16-10113ETIS-WP6-Report-Publishable-Summary.pdf> [Accessed 18 February 2020].
28 Renewable UK. (2020). Wind Energy [Online]. Available at: <https://www.renewableuk.com/page/WindEnergy> [Accessed 10 February 2020].
29 Equinor.com. (2020). The market outlook for floating offshore wind [Online]. Equinor. Available at: <https://www.equinor.com/en/what-we-do/floating-wind/the-market-outlook.html> [Accessed 10 February 2020].
30 Wood Mackenzie. (2019). Europe offshore wind power outlook 2019
31 Wood Mackenzie. (2019). Potential impact of hard Brexit on the UK offshore wind industry
32 Committee on Climate Change. (2019). Net Zero – The UK’s contribution to stopping global warming [Online]. Available at: <https://www.theccc.org.uk/publication/net-zero-the-uks-contribution-to-stopping-global-warming/> [Accessed 10 February 2020].
33 The Crown Estate. (2020). On the seabed and coast [Online]. Available at: <https://www.thecrownestate.co.uk/en-gb/what-we-do/on-the-seabed/> [Accessed 13 February 2020].
34 The Crown Estate. (2020). Offshore wind [Online]. Available at: <https://www.crownestatescotland.com/what-we-do/marine/asset/offshore-wind> [Accessed 13 February 2020].
35 Oil & Gas Authority. (2018). Carbon Capture Storage Licence Awarded [Online]. Available at: <https://www.ogauthority.co.uk/news-publications/news/2018/carbon-capture-storage-licence-awarded/> [Accessed 18 February 2020].
36 Crown Estate Scotland. (2019). ScotWind Leasing, Seabed leasing for new offshore wind farms zero [Online]. Available at: <https://www.crownestatescotland.com/maps-and-publications/download/346> [Accessed 26 March 2020].
37 Wood Mackenzie. (2019). Potential impact of hard Brexit on the UK’s offshore wind industry
38 The Crown Estate. (2018). Offshore wind operational report. [Online]. Available at: <https://www.thecrownestate.co.uk/media/2950/offshore-wind-operational-report-2018.pdf> [Accessed 12 February 2020].
39 Wood Mackenzie. (2019). Global fixed-bottom offshore wind LCOE
40 The Crown Estate. (2019). The Crown Estate showcases another record-breaking year for UK offshore wind, with the launch of its 2018 Offshore Wind Operational Report [Online]. Available at: <https://www.thecrownestate.co.uk/en-gb/media-and-insights/news/2019-the-crown-estate-showcases-another-record-breaking-year-for-uk-offshore-wind-with-the-launch-of-its-2018-offshore-wind-operational-report/> [Accessed 12 February 2020].
41 Wood Mackenzie. (2019). The Momentum of Floating Wind and its Outlook Implications
42 Wood Mackenzie. (2020). Power & Renewables - Global Utility-Scale Solar PV Project Database
43 Wood Mackenzie. (2019). Floating solar landscape 2019
44 Wood Mackenzie solar expert
45 Oceansofenergy.blue. (2019). A world’s first: offshore floating solar farm installed at the Dutch North Sea [Online]. Oceans of Energy. Available at: <https://oceansofenergy.blue/2019/12/11/a-worlds-first-offshore-floating-solar-farm-installed-at-the-dutch-north-sea/> [Accessed 12 February 2020].
46 Rechargenews.com. (2019). World’s first ‘high-wave’ floating PV array to be built off Belgium [Online]. Recharge. Available at: <https://www.rechargenews.com/transition/world-s-first-high-wave-floating-pv-array-to-be-built-off-belgium/2-1-641095> [Accessed 12 February 2020].
47 International Energy Agency. (2020). Data and Statistics [Online]. Available at: <https://www.iea.org/data-and-statistics?country=UK&fuel=Renewables%20and%20waste&indicator=%20Renewable%20share%20(modern%20renewables)%20in%20final%20energy%20consumption%20(SDG%207.2)%20> [Accessed 10 February 2020].
48 UK Government. (2013). Wave and tidal energy: part of the UK’s energy mix [Online]. Available at: <https://www.gov.uk/guidance/wave-and-tidal-energy-part-of-the-uks-energy-mix> [Accessed 18 February 2020].
49 Offshore Renewable Energy Catapult. (2018). Tidal stream and wave energy cost reduction and industrial benefit [Online]. Available at: <https://www.marineenergywales.co.uk/wp-content/uploads/2018/05/ORE-Catapult-Tidal-Stream-and-Wave-Energy-Cost-Reduction-and-Ind-Benefit-FINAL-v03.02.pdf> [Accessed 10 February 2020].
50 Offshore Renewable Energy Catapult. (2019). Annual Report 18/19 [Online]. Available at: <https://ore.catapult.org.uk/reports-and-resources/reports-publications/ore-catapult-reports/> [Accessed 10 February 2020].
51 Energy Research Partnership. (2016). Potential Role of Hydrogen in the UK Energy System [Online]. Available at: <http://erpuk.org/wp-content/uploads/2017/01/ERP-hydrogen-report-oct-2016.pdf> [Accessed 20 February 2020].
52 Committee on Climate Change. (2019). Net Zero – Technical Report [Online]. Available at: <https://www.theccc.org.uk/publication/net-zero-technical-report/> [Accessed 10 February 2020].
53 IRENA. (2019). Hydrogen: A renewable energy perspective [Online]. Available at: <https://www.irena.org/publications/2019/Sep/Hydrogen-A-renewable-energy-perspective> [Accessed 1 April 2020].
54 Wood Mackenzie. (2019). Green hydrogen production: Landscape, projects and costs
55 IRENA. (2018). Hydrogen from Renewable Power, technology outlook for the energy transition [Online]. Available at: <https://www.irena.org/-/media/Files/IRENA/Agency/Publication/2018/Sep/IRENA_Hydrogen_from_renewable_power_2018.pdf> [Accessed 1 April 2020].
56 UK Hydrogen and Fuel Cell Association. (2020). Hydrogen [Online]. Available at: <http://www.ukhfca.co.uk/the-industry/hydrogen/> [Accessed 10 February 2020].
57 Newscientist.com. (2020). UK could use hydrogen instead of natural gas – if it can make enough [Online]. New Scientist. Available at: <https://www.newscientist.com/article/2206546-uk-could-use-hydrogen-instead-of-natural-gas-if-it-can-make-enough/> [Accessed 10 February 2020].
58 Department for Business, Energy & Industrial Strategy. (2019). Business Models for Carbon Capture, Usage and Storage; A consultation seeking views on potential business models for carbon capture, usage and storage Zero [Online]. Available at: <https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/819648/ccus-business-models-consultation.pdf> [Accessed 17 March 2020].
59 Rechargenews.com. (2019). Floating wind-to-hydrogen plan to heat millions of UK homes [Online]. Recharge. Available at: <https://www.rechargenews.com/wind/floating-wind-to-hydrogen-plan-to-heat-millions-of-uk-homes/2-1-670960> [Accessed 03 March 2020].
60 Itm-power.com. (2019). Gigastack Feasibility Study with Ørsted [Online]. ITM Power. Available at: <https://www.itm-power.com/item/58-project-to-demonstrate-delivery-of-bulk-low-cost-and-zero-carbon-hydrogen-through-gigawatt-scale-pem-electrolysis-manufactured-in-the-uk> [Accessed 18 February 2020].
61 Drax.com. (2019). Leading energy companies announce new zero-carbon UK partnership [Online]. Drax. Available from <https://www.drax.com/press_release/energy-companies-announce-new-zero-carbon-uk-partnership-ccus-hydrogen-beccs-humber-equinor-national-grid/> [Accessed 10 February 2020].
62 Wood Mackenzie. (2020). Carbon capture and storage
63 Edie.net. (2020). Clean transport, CCS and biodiversity championed in Budget 2020 homes [Online]. Edie. Available at: <https://www.edie.net/news/11/Clean-transport--CCS-and-biodiversity-championed-in-Budget-2020/> [Accessed 12 March 2020].
64 CCUS Cost Challenge Taskforce. (2018). Delivering clean growth: CCUS Cost Challenge Taskforce report System [Online]. Available at: <https://www.gov.uk/government/publications/delivering-clean-growth-ccus-cost-challenge-taskforce-report> [Accessed 20 February 2020].
65 Wood Mackenzie. (2020). Future energy – carbon capture and storage
66 Carbon Capture & Storage Association. (2020). CCS projects and proposals [Online]. CCSa Available at: <http://www.ccsassociation.org/why-ccs/ccs-projects/current-projects/> [Accessed 10 February 2020].
67 Department for Business, Energy & Industrial Strategy. (2019) Digest of UK Energy Statistics 2019 [Online]. Available at: <https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/820277/DUKES_2019_Press_Notice_GOV.UK.pdf> [Accessed 10 February 2020].
68 Department for Business, Energy & Industrial Strategy. (2019). Natural gas imports and exports [Online]. Available at: <https://www.gov.uk/government/statistics/natural-gas-chapter-4-digest-of-united-kingdom-energy-statistics-dukes> [Accessed 18 February 2020].
69 European Commission. (2019) A European strategic long term vision for a prosperous, modern, competitive and climate neutral economy. [online] Available at: <https://ec.europa.eu/energy/sites/ener/files/documents/2_dgclima_rungemetzger.pdf> [Accessed 18 February 2020]
70 European Commission. (2019). What is the European Green Deal [Online]. Available at: <https://ec.europa.eu/commission/presscorner/detail/en/fs_19_6714> [Accessed 18 February 2020].
71 Oil & Gas UK. (2019). Roadmap 2035: A blueprint for net-zero [Online]. Available at: <https://www.energyvision2035.com/roadmap-2035/helping-meet-uk-energy-needs> [Accessed 26 March 2020].
72 Oil & Gas UK. (2019). Energy Transition Outlook 2019. [online]. Available at: <https://oilandgasuk.co.uk/wp-content/uploads/2019/12/OGUK-Energy-Transition-Outlook-2019.pdf> [Accessed 10 February 2020]
73 IEA.org. (2020). Fuels and technologies: gas. [online] IEA. Available at: <https://www.iea.org/fuels-and-technologies/gas> [Accessed 4 May 2020].
74 Theogtc.com. (2018). Application of data analytics technologies to improve asset operations and maintenance. [online] OGTC. Available at: <https://www.theogtc.com/media/2380/digital-landscaping-study-of-the-oil-and-gas-sector-application-of-data-analytics-technologies-to-improve-asset-operations-and-maintenance.pdf> [Accessed 4 May 2020].
75 Oilandgasuk.co.uk. (2019). Environment report 2019. [online] OGUK. Available at: <https://oilandgasuk.cld.bz/Environment-Report-2019> [Accessed 4 May 2020].
76 Ogauthority.co.uk. (2019). UKSC energy integration interim findings. [online] O&G Authority. Available at: <https://www.ogauthority.co.uk/media/6257/ukcs-energy-integration-interim-findings.pdf> [Accessed 4 May 2020].
77 Sintef.no. (2013). Offshore energy efficiency technologies. [online] Sintef. Available at: <https://www.sintef.no/globalassets/project/effort/effort-presentation-at-the-otc-conference-houston-may-6-2013.pdf> [Accessed 4 May 2020].
78 Equinor (2020). A breakthrough in emissions reductions. [online] Equinor. Available at <https://www.equinor.com/en/what-we-do/johan-sverdrup/climate.html> [Accessed 29 June 2020].
79 Rystadenergy.com. (2017). Electrifying the Barents Sea. [online] Rystad Energy. Available at: <https://www.rystadenergy.com/newsevents/news/press-releases/electrifying-the-barents-sea/> [Accessed 4 May 2020].
80 Riboldi, L., Voller, S., Korpas, M.and Nord, L. O. (2019). An Integrated Assessment of the Environmental and Economic Impact of Offshore Oil Platform Electrification. Energies, 12(11), p. 2114.
226 227
Refe
renc
es |
Febr
uary
202
0
Refe
renc
es |
Febr
uary
202
0
81 Nieradzinska, K., MacIver, C., Gill, S., Agnew, G. A., Anaya-Lara, O.and Bell, K. R. W. (2016). Optioneering analysis for connecting Dogger Bank offshore wind farms to the GB electricity network. Renewable Energy, 91, p. 120-129.
82 Windpowermonthly.com. (2019). How can innovation in submarine cabling reduce costs for offshore wind?. [online] Wind Power Monthly. Available at: <https://www.windpowermonthly.com/article/1664467/innovation-submarine-cabling-reduce-costs-offshore-wind> [Accessed 28 April 2020].
83 Oedigital.com (2020). Tapping Shore Power for Offshore Oil and Gas Facilities. [online] Offshore Engineer. Available at: <https://www.oedigital.com/news/475350-tapping-shore-power-for-offshore-oil-and-gas-facilities> [Accessed 27 April 2020].
84 Xiang, X., Merlin, M. M. C., and Green, T. C. (2016). Cost analysis and comparison of HVAC, LFAC and HVDC for offshore wind power connection. IET International Conference on AC and DC Power Transmission 2016, Beijing, p. 1-6.
85 Abb.com. (2020). HVDC: economic and environmental advantages. [online] ABB. Available at: <https://new.abb.com/systems/hvdc/why-hvdc/economic-and-environmental-advantages> [Accessed 28 April 2020].
86 Abb.com. (2019). Johan Sverdrup. [online] ABB. Available at: <https://new.abb.com/oil-and-gas/case-studies/offshore/johan-sverdrup> [Accessed 28 April 2020].
87 Hartel, P., Vrana, T. K., Hennig, T., von Bonin, M., Wiggelinkhuizen, E., and Nieuwenhout, F. (2017). Review of investment model cost parameters for VSC HVDC transmission infrastructure. Electric Power Systems Research, 151, p. 419-431.
88 Northseaenergy.eu. (2019). Synthesis paper. [online] North Sea Energy. Available at: <https://www.north-sea-energy.eu/documents/NSE2%20%20Deliverable%20Synthesis%20paper.pdf> [Accessed 4 May 2020].
89 Kivi.nl. (2019). An outlook on the integration of North Sea energy systems. [online] KIVI. Available at: <https://www.kivi.nl/uploads/media/5d00e297ec523/20190605%20KIVI-O&G%20-%20An%20outlook%20on%20the%20integration%20of%20North%20Sea%20energy%20systems%2005.06.209.pdf> [Accessed 28 April 2020].
90 Oilandgasuk.co.uk. (2015). Offshore Gas Turbines and Dry Low NOx Burners - An analysis of the Performance Improvements (PI) Limited Database. [online] Oil & Gas UK. Available at: <https://oilandgasuk.co.uk/wp-content/uploads/2015/05/producys-cayrgory.pdf> [Accessed 28 April 2020].
91 Epa.gov. (2011). Electric compressors PRO Fact Sheet. [online] EPA. Available at: <https://www.epa.gov/sites/production/files/2016-06/documents/installelectriccompressors.pdf> [Accessed 28 April 2020].
92 Chrysaor, (2020). ‘Primary Research’.
93 Windpowermonthly.com (2017). Boundary Pushers: The offshore meshed grid challenge. [online] Wind Power Monthly. Available at: <https://www.windpowermonthly.com/article/1446911/boundary-pushers-offshore-meshed-grid-challenge> [Accessed 28 April 2020].
94 TNO.nl. (2011). WP 3: technologies state of the art, Task 3: grid integration aspects. [online] ORECCA. Available at: <https://publications.tno.nl/publication/34629094/b7N68c/e11014.pdf> [Accessed 28 April 2020].
95 Offshoreenergy.biz. (2019). Goliat field support vessel completes first stage of hybrid power conversion. [online] Offshore Energy. Available at: <https://www.offshore-energy.biz/goliat-field-support-vessel-completes-first-stage-of-hybrid-power-conversion/> [Accessed 28 April 2020].
96 Abb.com. (2017). Valhalla power from shore after five years of operation. [online] ABB. Available at: <https://library.e.abb.com/public/b1dfd6e22ebc402fb11e86726619aece/VALHALL%20HVDC%20Power%20From%20Shore%205%20years%20experience%20,%20EUR17_35.pdf> [Accessed 28 April 2020].
97 Offshoremag.com. (2020). Equinor launches emissions offensive. [online] Offshore Magazine. Available at: <https://www.offshore-mag.com/regional-reports/article/14168426/equinor-launches-emissions-offensive> [Accessed 28 April 2020].
98 Energyvoice.com. (2019). BP boss confirms green power plans for North Sea platforms. [online] Energy Voice. Available at: <https://www.energyvoice.com/oilandgas/north-sea/213349/bp-boss-confirms-green-power-plans-for-north-sea-platforms/> [Accessed 28 April 2020].
99 Upstreamonline.com. (2019). BP eyeing low carbon power for Clair South. [online] Upstream Online. Available at: <https://www.upstreamonline.com/low-carbon/bp-eyeing-low-carbon-power-for-clair-south/2-1-718140> [Accessed 28 April 2020].
100 IEA.org. (2019). Tracking fuel supply. [online] IEA. Available at: <https://www.iea.org/reports/tracking-fuel-supply-2019/flaring-emissions> [Accessed 2 May 2020].
101 Oilandgasuk.co.uk. (2019). Economic report 2019. [online] OGUK. Available at: <https://oilandgasuk.co.uk/wp-content/uploads/2019/09/Economic-Report-2019-OGUK.pdf> [Accessed 4 May 2020].
102 Egyptoil-gas.com. (2016). Norwegion Lesson in Gas Flare Elimination. [online] Egypt Oil and Gas. Available at: <https://egyptoil-gas.com/features/norwegian-lesson-in-gas-flare-elimination/> [Accessed 2 May 2020].
103 Draugen.industriminne.no. (2018). Draugen gas – flaring or reinjection. [online] Draugen Field. Available at: <https://draugen.industriminne.no/en/2018/04/27/draugen-gas-flaring-or-reinjection/> [Accessed 3 May 2020].
104 Gbadamosi, A. O., Kiwalabye, J., Junin, R., and Augustine, A. (2018). A review of gas enhanced oil recovery schemes used in the North Sea. Journal of Petroleum Exploration and Production Technology, 8, p. 1373–1387.
105 Sccs.org.uk. (2014). A Review of Flaring and Venting at UK Offshore Oilfields. [online] SCCS. Available at: <http://www.sccs.org.uk/images/expertise/reports/co2-eor-jip/SCCS-CO2-EOR-JIP-WP11-Flaring-Venting.pdf> [Accessed 2 May 2020].
106 Bsee.gov. (2017). Venting and Flaring Research Study Report. [online] BSEE. Available at: <https://www.bsee.gov/sites/bsee.gov/files/5007aa.pdf#page=176&zoom=100,45,104> [Accessed 1 May 2020].
107 Schmidt, D., and Oster, B. (2007). Low-BTU Field Gas Application to Microturbines. [online] University of North Dakota. doi: 10.2172/986862.
108 ogauthority.co.uk (2016). Flaring and Venting During the Production Phase. Available at: <https://www.ogauthority.co.uk/media/2467/flaring-and-venting-during-the-production-phase-1016.pdf> [Accessed 29 June 2020]
109 SCCS.org.uk (2014) A Review of Flaring and Venting at UK Offshore Oilfields. Available at: <http://www.sccs.org.uk/images/expertise/reports/co2-eor-jip/SCCS-CO2-EOR-JIP-WP11-Flaring-Venting.pdf> [Accessed 29 June 2020]
110 Worldbank.org. (2020). Zero Routine Flaring by 2030. [online] World Bank. Available at: <https://www.worldbank.org/en/programs/zero-routine-flaring-by-2030> [Accessed 2 May 2020].
111 Offshore-Technology.com. (2020). OGUK sets out plans to decarbonise the UK oil and gas industry. [online] OT. Available at: < https://www.offshore-technology.com/news/oguk-sets-out-plans-to-decarbonise-the-uk-oil-and-gas-industry/> [Accessed 8 May 2020]
112 IEA.org. (2020). Methane tracker. [online] IEA. Available at: <https://www.iea.org/reports/methane-tracker-2020/methane-from-oil-gas> [Accessed 2 May 2020].
113 Princeton.edu. (2019). Offshore oil and gas rigs leak more greenhouse gas than expected. [online] Princeton University. Available at: <https://www.princeton.edu/news/2019/08/15/offshore-oil-and-gas-rigs-leak-more-greenhouse-gas-expected> [Accessed May 1 2020].
114 IEA.org (2020). Methane Tracker 2020: Interactive Country and Regional Estimates. IEA. Available at: <https://www.iea.org/reports/methane-tracker/country-and-regional-estimates> [Accessed 29 May 2020].
115 Oil & Gas UK. (2020). Pathway to a Net-Zero Basin: Production Emissions Targets. [online]. Available athttps://oilandgasuk.co.uk/wp-content/uploads/2020/06/OGUK-Production-Emissions-Targets-Report-2020.pdf [Accessed 22 June 2020].
116 Offshore Engineer. (2013). Offshore pipeline leak detection for Arctic application. [online] OE. Available at: <http://9f50f0311489b2d45830-9c9791daf6b214d0c0094462a66ea80c.r0.cf3.rackcdn.com/offshore-pipeline-detection.pdf> [Accessed 1 May 2020].
117 Eagle.org. (2019). Subsea inspection, maintenance and repair advisory. [online] ABS. Available at: <https://ww2.eagle.org/content/dam/eagle/advisories-and-debriefs/ssimr-advisory-19016.pdf> [Accessed 2 May 2020].
118 Adegboye, M. A., Fung, W., and Karnik, A. (2019). Recent Advances in Pipeline Monitoring and Oil Leakage Detection Technologies: Principles and Approaches. Sensors, 19, p. 2548.
119 Shama, A., Bady, A., El-Shaib, M. N., and Kotb, M. A. (2017). Review of leakage detection methods for subsea pipeline. 17th International Congress of the International Maritime Association of the Mediterranean (IMAM 2017), Lisbon.
120 Aogexpo.com.au. (2015). Real-time Subsea Pipeline Leak Monitoring using Fiber Optic Sensing Technology. [online] INTECSEA. Available at: <https://aogexpo.com.au/wp-content/uploads/2015/03/Real-time-Subsea-Pipeline-Leak-Monitoring-using-Fiber-Optic-Sensing-Technology.pdf> [Accessed 1 May 2020].
121 Ogauthority.co.uk. (2016). UKCS Exploration & Appraisal Status. [online] O&G Authority. Available at: <https://www.ogauthority.co.uk/media/3163/oga-gunther-newcombe-keynote-presentation-prospex-december-2016-public.pdf> [Accessed 4 May 2020].
122 Ramberg, R. M., Davies, S. R., Rognoe, H., and Oekland, O. (2013). Steps to the Subsea Factory. Offshore Technology Conference 2013, Rio de Janeiro.
123 Lux Research, (2017). Advancements at the Seabed – The Future of Subsea Production in the Low Oil Price Era.
124 Lux Research, (2018). The OGTC and Total partner with Crondall Energy for reusable production buoys for the North Sea.
125 Atkinsglobal.com. (2020). DDPSO - expanding the flexibility of FPSOs. [online] Atkins Global. Available at: <https://www.atkinsglobal.com/en-gb/projects/ddpso> [Accessed 1 May 2020].
126 Akersolutions.com. (2020). Floater Designs. [online] Aker Solutions. Available at: <https://www.akersolutions.com/what-we-do/products-and-services/floater-designs/> [Accessed 28 April 2020].
127 Chrysaor, (2020). ‘Primary Research.
128 Offshore-technology.com. (2008). Decommissioning the North Sea. [online] Offshore Technology. Available at: <https://www.offshore-technology.com/features/feature2069/> [Accessed 3 May 2020].
129 Akersolutions.com. (2019). Subsea Compression & Processing: Reducing the Industry’s Carbon Footprint. [online] Aker Solutions. Available at: <https://www.norwep.com/content/download/40666/297970/version/1/file/Drew+Sage% 2C+Technical+Director+Front+End+%E2%80%93+Australia% 2C+Aker+Solutions.pdf> [Accessed 28 April 2020].
130 Marinetechnologynews.com. (2018). Powering the Seafloor: Put a Plug in It. [online] Marine Technology News. Available at: <https://www.marinetechnologynews.com/news/powering-seafloor-socket-561313> [Accessed 1 May 2020].
131 Marinetechnologynews.com. (2019). Chevron to Use Subsea Compression at Jansz-Io. [online] Marine Technology News. Available at: <https://www.marinetechnologynews.com/news/chevron-subsea-compression-jansz-586913> [Accessed 1 May 2020].
132 Turbomachinerymag.com. (2011). The hermetically sealed compressor for offshore and subsea. [online] Turbo Machinery Mag. Available at: <https://www.turbomachinerymag.com/the-hermetically-sealed-compressor-for-offshore-and-subsea/> [Accessed 28 April 2020].
133 Oedigital.com (2020). Aker, MAN shrink subsea compression size, costs. [online] Offshore Engineer. Available at: <https://www.oedigital.com/news/448183-aker-man-shrink-subsea-compression-size-costs> [Accessed 4 May 2020].
134 ABB.com. (2017). Subsea variable speed drive successfully tested under water. [online] ABB. Available at: <https://new.abb.com/news/detail/2811/subsea-variable-speed-drive-successfully-tested-under-water> [Accessed 4 May 2020].
135 Dredgingandports.com. (2019). Subsea power grids undergo final testing. [online] Dredging and Port Construction. Available at: <https://dredgingandports.com/news/2019/subsea-power-grids-undergo-final-testing/> [Accessed 5 May 2020].
136 Forbes.com. (2019). . [online] ABB Strikes ‘Holy Grail’ Of Subsea Power Systems For Offshore Energy Rigs. Available at: <https://www.forbes.com/sites/gauravsharma/2019/11/20/abb-strikes-holy-grail-of-subsea-power-systems-for-offshore-energy-rigs/#7c385a487a82> [Accessed 27 April 2020].
137 Gep.com. (2019). The Circular Economy: An Innovative Path to Sustainability in Oil and Gas. [online] GEP. Available at: <https://www.gep.com/mind/blog/the-circular-economy-an-innovative-path-to-sustainability-in-oil-and-gas> [Accessed 5 May 2020].
138 Offshore-mag.com. (2020). Subsea standardization initiatives aim to remove uncertainty, improve quality. [online] publisher. Available at: <https://www.offshore-mag.com/subsea/article/14172696/subsea-standardization-initiatives-aim-to-remove-uncertainty-improve-quality> [Accessed 3 May 2020].
139 Proton.energy. (2019). Protein Technologies. [online]. Available at: < http://proton.energy/> [Accessed May 8 2020}
140 Wood Mackenzie, (2020). Gauging the unsubsidized offshore wind potential in the UK, April 2020.
141 Wood Mackenzie, (2020). Global offshore wind power project database, Q1 2020.
142 Lux Research, (2019). General Electric and Vattenfall join forces on 12 MW Haliade-X offshore turbine.
143 Cleantechnica.com. (2019). GE Renewable Energy Unveils 12 Megawatt Haliade-X Offshore Wind Nacelle. [online] Clean Technica. Available at: <https://cleantechnica.com/2019/07/23/ge-renewable-energy-unveils-12-megawatt-haliade-x-offshore-wind-nacelle/> [Accessed 1 May 2020].
144 Genewsroom.com. (2019). World’s biggest offshore wind turbine heading to the UK for testing. [online] GE. Available at: <https://www.genewsroom.com/press-releases/worlds-biggest-offshore-wind-turbine-heading-uk-testing> [Accessed 29 April 2020].
145 Windeurope.org. (2018). Floating offshore wind energy: a policy blueprint for Europe. [online] Wind Europe. Available at: <https://windeurope.org/wp-content/uploads/files/policy/position-papers/Floating-offshore-wind-energy-a-policy-blueprint-for-Europe.pdf> [Accessed 30 April 2020].
146 Konstantinidis, E. I., and Botsaris, P. (2016). Wind turbines: current status, obstacles, trends and technologies. IOP Conference Series Materials Science and Engineering, 161.
147 Greentechmedia.com. (2020). UK Considers Support Measures to Fire Up Floating Offshore Wind Market. [online] GTM. Available at: <https://www.greentechmedia.com/articles/read/more-momentum-for-floating-wind> [Accessed 1 May 2020].
148 Cleantechnica.com. (2018). UK Floating Wind Could Support 17,000 Jobs & Generate £33.6 Billion In Value By 2050. [online] Clean Technica. Available at: <https://cleantechnica.com/2018/10/30/uk-floating-wind-could-support-17000-jobs-generate-33-6-billion-in-value-by-2050/> [Accessed 1 May 2020].
149 Techcrunch.com. (2020). Alphabet takes the wind out of its Makani energy kites. [online] Tech Crunch. Available at: <https://techcrunch.com/2020/02/18/alphabet-takes-the-wind-out-of-its-makani-energy-kites/> [Accessed 29 April 2020].
150 Compositesworld.com. (2019). SAERTEX provides material for 87.5-meter carbon fiber spar cap. [online] Composites World. Available at: <https://www.compositesworld.com/news/saertex-provides-material-for-875-meter-carbon-fiber-spar-cap> [Accessed 30 April 2020].
151 Compositesworld.com. (2019). Wind blade spar caps: Pultruded to perfection? [online] Composites World. Available at: <https://www.compositesworld.com/articles/wind-blade-spar-caps-pultruded-to-perfection> [Accessed 30 April 2020].
152 Lux Research, (2019). Saertex demonstrates record-length carbon fiber composite spar cap for wind turbine blades at 87.5 meters.
153 Salic, T., Charpentier, J. F., Benbouzid, M., and Boulluec M. L. (2019). Control Strategies for Floating Offshore Wind Turbine: Challenges and Trends. Electronics, [online]. Available at: <https://www.mdpi.com/2079-9292/8/10/1185/pdf> [Accessed 30 April 2020].
154 Zxlidars.com. (2020). The home of remote sensor performance verifications. [online]. ZX Lidars. Available at: <https://www.zxlidars.com/wind-measurement-services-lidar/remote-sensing-device-lidar-test-site/> [Accessed 3 May 2020].
155 Institute for Energy Research (2020). The Cost of Decommissioning Wind Turbines is Huge. [Online]. Available at https://www.instituteforenergyresearch.org/renewable/wind/the-cost-of-decommissioning-wind-turbines-is-huge/ [Accessed 26 May 2020].
156 Butterfield, S., Musial, W., Jonkman, J.and Sclavounos, P. (2005). Engineering challenges for floating offshore wind turbines. [online] NREL Conference September 2007, Copenhagen. Available at: <https://www.nrel.gov/docs/fy07osti/38776.pdf> [Accessed 3 May 2020].
157 Windeurope.org (2018). Floating Offshore Wind Energy, a policy blueprint for Europe. [pdf]. Wind Europe Available at <https://windeurope.org/wp-content/uploads/files/policy/position-papers/Floating-offshore-wind-energy-a-policy-blueprint-for-Europe.pdf/> [Accessed 26 May 2020].
158 Taninoki, R, Abe, K., Sukegawa, T., Azuma, D., and Nishikawa, M. (2017). Dynamic Cable System for Floating Offshore Wind Power Generation. SEI Technical Review, 84.
159 Irena.org. (2019). Future of Wind: Deployment, investment, technology, grid integration and socio-economic aspects. [online] IRENA. Available at: <https://www.irena.org/-/media/Files/IRENA/Agency/Publication/2019/Oct/IRENA_Future_of_wind_2019.pdf> [Accessed 3 May 2020].
160 Physicsworld.com. (2019). The promise and challenges of airborne wind energy. [online] Physics World. Available at: <https://physicsworld.com/a/the-promise-and-challenges-of-airborne-wind-energy/> [Accessed 4 May 2020].
161 DNVGL.com (2020). WIN WIN - Wind-powered water injection. [online]. Available at <https://www.dnvgl.com/energy/feature-articles/win-win-wind-powered-water-injection.html>. [Accessed 26 May 2020].
162 Bbc.com. (2014). Wave power firm Pelamis calls in administrators. [online] BBC. Available at: <https://www.bbc.com/news/uk-scotland-scotland-business-30151276> [Accessed 5 May 2020].
163 Emec.org.uk. (2015). Pathway to commercialisation: an EMEC guide to research, development, and testing of marine energy technology. [online] EMEC. Available at: <http://www.emec.org.uk/?wpfb_dl=188 > [Accessed 4 May 2020].
228 229
Refe
renc
es |
Febr
uary
202
0
Refe
renc
es |
Febr
uary
202
0
164 Simecatlantis.com. (2020). Meygen. [online] SIMEC Atlantis Energy. Available at: <https://simecatlantis.com/projects/meygen/> [Accessed 4 May 2020].
165 Cnbc.com. (2020). A tidal project in Scottish waters just generated enough electricity to power nearly 4,000 homes. [online] CNBC. Available at: <https://www.cnbc.com/2020/01/27/tidal-project-generates-electricity-to-power-nearly-4000-homes.html> [Accessed 5 May 2020].
166 Nbcnews.com. (2020). Tidal energy pioneers see vast potential in ocean currents’ ebb and flow. [online] NBN News. Available at: <https://www.nbcnews.com/mach/science/tidal-energy-pioneers-see-vast-potential-ocean-currents-ebb-flow-ncna981341> [Accessed 5 May 2020].
167 Cleantechnica.com. (2020). MeyGen Tidal Power Facility Exported 13.8 GWh Of Electricity To The UK Grid In 2019. [online] Clean Technica. Available at: <https://cleantechnica.com/2020/01/29/meygen-tidal-power-facility-exported-13-8-gwh-of-electricity-to-the-uk-grid-in-2019/> [Accessed 5 May 2020].
168 Deepresource.wordpress.com. (2012). Tidal Energy Animation. [Blog] DeepResource. Available at: <https://deepresource.wordpress.com/2012/04/20/tidal-energy-animation/> [Accessed 3 May 2020].
169 Emec.org.uk. (2020). Magallanes Renovables. [online] EMEC. Available at: <http://www.emec.org.uk/about-us/our-tidal-clients/magallanes-renovables/> [Accessed 1 May 2020].
170 Orbitalmarine.com. (2020). Orbital O2 2MW. [online] Orbital. Available at: <https://orbitalmarine.com/technology-development/catching-the-tide/orbital-o2> [Accessed 1 May 2020].
171 Lux Research, (2019). Innovations in Wave and Tidal Energy.
172 hal.archives-ouvertes.fr. (2015). Marine Renewable Energy Converters and Biofouling: A Review on Impacts and Prevention. [online] HAL. Available at: <https://hal.archives-ouvertes.fr/hal-01199624/document> [Accessed 4 May 2020].
173 Marineenergy.biz. (2018). CTC presents new protective coating for marine renewables. [online] Marine Energy. Available at: <https://marineenergy.biz/2018/02/01/ctc-presents-new-protective-coating-for-marine-renewables/> [Accessed 4 May 2020].
174 Phys.org. (2016). Long-lasting coatings for offshore renewable energy. [online] Phys.org. Available at: <https://phys.org/news/2016-02-long-lasting-coatings-offshore-renewable-energy.html> [Accessed 3 May 2020].
175 Marinenergy.biz. (2019). RoBFMS Project to Deploy Marine Energy Anti-Fouling System at Orkney Test Site. [online] Marine Energy. Available at: <https://marineenergy.biz/2019/09/13/robfms-project-to-deploy-marine-energy-anti-fouling-system-at-orkney-test-site/> [Accessed 28 April 2020].
176 Greentechmedia.com. (2019). Floating Solar Gets Ready for the High Seas. [online] GTM. Available at: <https://www.greentechmedia.com/articles/read/floating-solar-gears-up-for-the-high-seas> [Accessed 28 April 2020].
177 Ogauthority.co.uk. (2018). Gas-to-Wire: UK SNS & EIS. [online] UK Oil & Gas Authority. Available at: <https://www.ogauthority.co.uk/media/5049/oil-gas-gas-to-wire.pdf> [Accessed 29 April 2020].
178 Northseawindpowerhub.eu. (2019). Cost Evaluation of North Sea Offshore Wind Post 2030. [online] TNO. Available at: < https://northseawindpowerhub.eu/wp-content/uploads/2019/02/112522-19-001.830-rapd-report-Cost-Evaluation-of-North-Sea-Offshore-Wind....pdf > [Accessed 27 April 2020].
179 Enbw.com.tw. (2019). Insight into an Offshore Wind Farm: Turbines – Powering Offshore Wind Farms. [online] EnBW. Available at: <https://www.enbw.com.tw/en/blog_content.aspx?serno=45¬=1585606713994> [Accessed 29 April 2020].
180 New.abb.com. (2018). HVDC technology for offshore wind is maturing. [online] ABB. Available at: <https://new.abb.com/news/detail/8270/hvdc-technology-for-offshore-wind-is-maturing> [Accessed 29 April 2020].
181 New.abb.com. (2020). Subsea Power Substation. [online] ABB. Available at: <https://new.abb.com/oil-and-gas/sectors/offshore-oil-and-gas/subsea/subsea-power/subsea-power-substation> [Accessed 29 April 2020].
182 Rigzone.com. (2019). New Subsea Era Could Begin with Power Tech. [online] Rigzone. Available at: <https://www.rigzone.com/news/new_subsea_era_could_begin_with_power_tech-03-dec-2019-160472-article/> [Accessed 4 May 2020].
183 Transformer-technology. (2019). ABB and Siemens test world’s first subsea substations for underwater factories. [online] Transformer Technology. Available at: <https://transformer-technology.com/news/us-news/431-subsea-power-grids-for-underwater-factories-receive-finishing-touches-transformer-technology.html> [Accessed 3 May 2020].
184 Viscas.com. (2013). Fukushima Floating Offshore Wind Farm Demonstration Project. [online] VISCAS. Available at: <http://www.viscas.com/english/e_news2013.10.html> [Accessed 3 May 2020].
185 Rivieramm.com. (2019). Aker Solutions: floating wind doesn’t need demos. [online] Riviera. Available at: <https://www.rivieramm.com/news-content-hub/news-content-hub/aker-solutions-floating-wind-doesnrsquot-need-demos-56863> [Accessed 28 April 2020].
186 Drax.com. (2018). Electric Insights: April to June 2018. [online] Drax. Available at: <https://www.drax.com/wp-content/uploads/2018/08/180809_Drax_Q2_Report.pdf> [Accessed 3 May 2020].
187 Based on WoodMacKenzie Energy Storage data for cumulative end of 2019, comprising 880MW front-of-the-meter, grid connected energy storage, 50MW non-residential (C&I), 40MW residential.
188 Cornwallinsight.com. (2018). Wholesale Power Price Cannibalisation. [online] Available at: <https://www.cornwall-insight.com/insight-papers/wholesale-power-price-cannibalisation> [Accessed 25 May 2020]
189 Fluenceenergy.com (2019), Energy Storage MythBusters. [online] Fluence Energy. Available at < https://blog.fluenceenergy.com/energy-storage-technologies-mythbusters> [Accessed 7 May 2020]
190 Maritime-executive.com. (2020). Expected to Transform the Offshore Supply Chain. [online] The Maritime Executive. Available at: <https://www.maritime-executive.com/article/2020-expected-to-transform-the-offshore-supply-chain> [Accessed 26 April 2020].
191 Offshore-energy.biz. (2018). ‘West Mira’ to become world’s first hybrid offshore rig. [online] Offshore Energy. Available at: <https://www.offshore-energy.biz/west-mira-to-become-worlds-first-hybrid-offshore-rig/> [Accessed 29 April 2020].
192 Lux Research, (2018). Siemens supplies first battery solution for offshore drilling rigs.
193 Cdn.ymaws.com. (2019). The UK Offshore Wind Industry: Supply chain review January 2019. [online] Offshore Wind Industry Council. Available at: <https://cdn.ymaws.com/www.renewableuk.com/resource/resmgr/publications/supply_chain_review_31.01.20.pdf> [Accessed 5 May 2020].
194 Cordis.europa.eu. (2020). Cost reduction and increase performance of floating wind technology. [online] CORDIS EU Commission. Available at: <https://cordis.europa.eu/project/id/815083> [Accessed 5 May 2020].
195 Analysis.newenergyupdate.com. (2018). GE launches 5.3 MW onshore wind turbine; Floating wind study calls for ‘urgent’ port spending. [online] New Energy Update. Available at: <http://analysis.newenergyupdate.com/wind-energy-update/ge-launches-53-mw-onshore-wind-turbine-floating-wind-study-calls-urgent-port > [Accessed 5 May 2020].
196 Ore.catapult.org.uk. (2019). An introduction to airborne wind. [online] Catapult. Available at: <https://ore.catapult.org.uk/analysisinsight/an-introduction-to-airborne-wind/> [Accessed 6 May 2020].
197 Nrel.gov. (2016). A Spatial-Economic CostReduction Pathway Analysis for U.S. Offshore Wind Energy Development from 2015–2030. [online] NREL. Available at: <https://www.nrel.gov/docs/fy16osti/66579.pdf> [Accessed 5 May 2020].
198 Lux Research, (2016). Batteries included in world’s first offshore floating wind farm.
199 Offshorenergystorage.com. (2020). FLASC Working Principle. [online] Offshore Energy Storage. Available at: <https://www.offshoreenergystorage.com/> [Accessed 25 April 2020].
200 Greentechmedia.com. (2016). Fraunhofer races hydrostor for underwater storage. [online] GTM. Available at: <https://www.greentechmedia.com/articles/read/fraunhofer-races-hydrostor-for-underwater-storage> [Accessed 30 April 2020].
201 EU Cordis (2017). Introducing the self-installing offshore wind turbine. Available at: <https://cordis.europa.eu/article/id/120526-introducing-the-selfinstalling-offshore-wind-turbine/> [Accessed May 8 2020].
202 Hydrogencouncil.com. (2020). Path to hydrogen competitiveness: a cost perspective. [online] Hydrogen Council. Available at: <https://hydrogencouncil.com/wp-content/uploads/2020/01/Path-to-Hydrogen-Competitiveness_Full-Study-1.pdf> [Accessed 5 May 2020].
203 IEA.org. (2019). The Future of Hydrogen. [online] IEA. Available at: <https://www.iea.org/reports/the-future-of-hydrogen> [Accessed 1 May 2020].
204 Nuoryon.com. (2019). BP, Nouryon and Port of Rotterdam partner on green hydrogen study. [online] Nuoryon. Available at: <https://www.nouryon.com/news-and-events/news-overview/2019/bp-nouryon-and-port-of-rotterdam-partner-on-green-hydrogen-study/> [Accessed 27 April 2020].
205 Greentechmedia.com. (2020). Shell Exploring World’s Largest Green Hydrogen Project. [online] Green Tech Media. Available at: <https://www.greentechmedia.com/articles/read/shell-exploring-worlds-largest-green-hydrogen-project> [Accessed 1 May 2020].
206 Thestar.com. (2020). Brunei ships 4.7 tonnes of hydrogen to Japan. [online] The Star. Available at: <https://www.thestar.com.my/news/regional/2020/02/21/brunei-ships-47-tonnes-of-hydrogen-to-japan> [Accessed 1 May 2020].
207 Ft.com (2019). Japan launched first liquid hydrogen carrier ship. [online]. Financial Times. Available at <https://www.ft.com/content/8ae16d5e-1bd4-11ea-97df-cc63de1d73f4/> [Accessed May 27 2020].
208 CCC (2019). Net Zero The UK’s contribution to stopping global warming [online]. CCC. Available at: <https://www.theccc.org.uk/wp-content/uploads/2019/05/Net-Zero-The-UKs-contribution-to-stopping-global-warming.pdf>
209 Afdc.energy.gov. (2001). Review of small stationary reformers for hydrogen production. [online] IEA. Available at: <https://afdc.energy.gov/files/pdfs/31948.pdf> [Accessed 2 May 2020].
210 Woodmac.com. (2019). Green hydrogen production: Landscape, projects and costs. [online] Wood Mackenzie. Available at: <https://www.woodmac.com/our-expertise/focus/transition/green-hydrogen-production-2019/> [Accessed 3 May 2020].
211 Franchi, C., Capocelli, M., Falco, M. D., Piemonte, V., and Barba, D. (2020). Hydrogen Production via Steam Reforming: A Critical Analysis of MR and RMM Technologies. Membranes, 10(1), p.10.
212 Sun, P., and Elgowainy, A. (2019). Updates of Hydrogen Production from SMR Process in GREET 2019. [online] Argonne National Laboratory. Available at: <https://greet.es.anl.gov/publication-smr_h2_2019> [Accessed 27 April 2020].
213 IEA.org. (2019). The clean hydrogen future has already begun. [online] IEA. Available at: <https://www.iea.org/commentaries/the-clean-hydrogen-future-has-already-begun> [Accessed 26 April 2020].
214 Irena.org. (2020). Hydrogen from Renewable Power. [online] IRENA. Available at: <https://www.irena.org/energytransition/Power-Sector-Transformation/Hydrogen-from-Renewable-Power> [Accessed 25 April 2020].
215 Tno.nl. (2020). Ten things you need to know about hydrogen. [online] TNO. Available at: <https://www.tno.nl/en/focus-areas/energy-transition/roadmaps/towards-co2-neutral-fuels-and-feedstock/hydrogen-for-a-sustainable-energy-supply/ten-things-you-need-to-know-about-hydrogen/> [Accessed 28 April 2020].
216 Ofgem.gov.uk. (2019). UKCS energy integration interim findings. [online] UK Oil & Gas Authority. Available at: <https://www.ofgem.gov.uk/system/files/docs/2019/12/ukcs_energy_integration-_interim_findings.pdf> [Accessed 28 April 2020].
217 Hygear.com. (2020). Hy Gen: on-site hydrogen generation. [online] Hy Gear. Available at: <https://hygear.com/technologies/hy-gen/> [Accessed 1 May 2020].
218 Cordis.europa.eu. (2019). Biogas membrane reformer for decentralIzed hydrogen production. [online] CORDIS EU Comission. Available at: <https://cordis.europa.eu/project/id/671459> [Accessed 2 May 2020].
219. Ieahydrogen.org. (2011). IEA-HIA Task 23 Small-scale Reformers for On-site Hydrogen Supply. [online] iea Energy Technology Network. Available at: <http://ieahydrogen.org/pdfs/Task23_Final-Report_ISBN.aspx> [Accessed 3 May 2020].
220 Chemengonline.com. (2015). Modular hydrogen production technology uses modified SMR process. [online] Chemical Engineering. Available at: <https://www.chemengonline.com/modular-hydrogen-production-technology-uses-modified-smr-process/> [Accessed 28 April 2020].
221 Taratova,E., et al. (2019). Plasma for environmental issues:From hydrogen production to 2D materials assenbly. [online] Technical University of Lisbon. Available at: < https://www.researchgate.net/publication/266799291_Plasmas_for_environmental_issues_From_hydrogen_production_to_2D_materials_assembly> [Accessed 26 May 2020].
222 Sintef.no. (2019). Hydrogen Production using Membrane-Assisted Autothermal Reforming Integrated with Chemical Looping Air Separation. [online] SINTEF. Available at: <https://www.sintef.no/globalassets/project/tccs-10/dokumenter/d2/tccs2019.pptx.pdf> [Accessed 1 May 2020].
223 Gti.energy. (2020). Low-carbon hydrogen – international project examines new technology. [online] GTI Energy. Available at: <https://www.gti.energy/low-carbon-hydrogen-international-project-examines-new-technology/> [Accessed 3 May 2020].
224 Greencarcongress.com. (2020). HyPER project using sorbent-enhanced steam reforming for low-carbon production of H2 from natural gas. [online] Green Car Congress. Available at: <https://www.greencarcongress.com/2020/02/20200219-hyper.html> [Accessed 28 April 2020].
225 Lux Research, (2020). Water Electrolysis Tech Page.
226 Irena.org. (2018). Hydrogen from renewable power: Technology outlook for the energy transition. [online] IRENA. Available at: <https://www.irena.org/publications/2018/Sep/Hydrogen-from-renewable-power> [Accessed 29 April 2020].
227 Lux Research, (2018). Thyssenkrupp makes a splash in water electrolysis by launching a highly efficient alkaline electrolyzer.
228 ITM-power.com. (2020). HGas3SP. [online] ITM Power. Available at: <https://www.itm-power.com/hgas3se> [Accessed 1 May 2020].
229 Theogtc.com. (2019). Phase 1 Project Report: Delivery of an offshore hydrogen supply programme via industrial trials at the Flotta Terminal. [online] publisher. Available at: <https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/866379/Phase_1_-_OGTC_-_Hydrogen_Offshore_Production.pdf> [Accessed 30 April 2020].
230 Babarit A, et al., Techno-economic feasibility of fleets of far offshore hydrogen-producing wind energy converters, International Journal of Hydrogen Energy (2018), https://doi.org/10.1016/j.ijhydene.2018.02.144
231 TNO, North Sea Energy Offshore System Integration (2018). Towards sustainable energy production on the North Sea - Green hydrogen production and CO2 storage: onshore or offshore? [Online]. Available at <https://energeia-binary-external-prod.imgix.net/2lakN2oy4sQF2hn1EzqXJ3LvK80.pdf?dl=North+Sea+Energy+I+-+Towards+sustainable+energy+production+on+the+North+Sea+-+Green+hydrogen+production+and+CO2+storage%3A+onshore+or+offshore%3F.pdf>. [Accessed 27 May 2020].
232 Ogauthority.co.uk. (2019). PosHYden Pilot: offshore green hydrogen. [online] Neptune Energy. Available at: <https://www.ogauthority.co.uk/media/6220/ogauthoritysharepointcom-ssl-davwwwroot-sites-ecm-tbw3-documents-files-exchange-malcolm-workshop-slides-301019-neptune.pdf> [Accessed 29 April 2020].
233 Offshorewind.biz. (2020). Ørsted and ITM Power Explore Different Approach to Integrating Offshore Wind and Hydrogen. [online] Offshore Wind. Available at: <https://www.offshorewind.biz/2020/04/13/orsted-and-itm-power-explore-different-approach-to-integrating-offshore-wind-and-hydrogen/> [Accessed 30 April 2020].
234 LinkedIn.com. (2019). Competition for World’s Largest Capacity Electrolyzer Factory. [online] NEL, ITM Power. Available at: <https://www.linkedin.com/pulse/competition-worlds-largest-capacity-electrolyzer-factory-patch/> [Accessed 28 April 2020].
235 Nrel.gov. (2019). Manufacturing Cost Analysis for Proton Exchange Membrane Water Electrolyzers. [online] NREL. Available at: <https://www.nrel.gov/docs/fy19osti/72740.pdf> [Accessed 29 April 2020].
236 Irena.org. (2019). Hydrogen: A renewable energy perspective. [online] IRENA. Available at: <https://www.irena.org/publications/2019/Sep/Hydrogen-A-renewable-energy-perspective> [Accessed 30 April 2020].
237 News.standford.edu. (2019). Stanford researchers create hydrogen fuel from seawater. [online] Stanford University. Available at: <https://news.stanford.edu/2019/03/18/new-way-generate-hydrogen-fuel-seawater/> [Accessed 29 April 2020].
238 Phys.org. (2018). A step closer to sustainable energy from seawater. [online] Phys.org. Available at: <https://phys.org/news/2018-08-closer-sustainable-energy-seawater.html> [Accessed 30 April 2020].
239 Parker.com. (2017). Desalination System Provides Ultra-Pure Water for Offshore Oil and Gas Rigs. [online] Parker. Available at: <http://blog.parker.com/desalination-system-provides-ultra-pure-water-for-offshore-oil-and-gas-rigs> [Accessed 30 April 2020].
240 Gov.uk. (2019). Dolphyn Hydrogen. [online] Department for Business, Energy and Industrial Strategy. Available at: <https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/866375/Phase_1_-_ERM_-_Dolphyn.pdf> [Accessed 30 April 2020].
241 Technischechemie.tu-berlin.de. (2019). Direct Electrolytic Splitting of Seawater: Opportunities and Challenges. [online] ACS Energy Letters. Available at: <https://www.technischechemie.tu-berlin.de/fileadmin/fg109/2019_ACS_Lett_S%C3%B6ren_Direct_Electrolytic_Splitting_of_Seawater.pdf> [Accessed 30 April 2020].
242 OGTC (2020). Mission sustainability: four more cleantech start-ups join award-winning technology accelerator. Available at <https://www.theogtc.com/newsroom/news/2020/mission-sustainability-four-more-cleantech-start-ups-join-award-winning-technology-accelerator/> [Accessed 26 May 2020}
243 Gtah2.com. (2019). Scalable Subsea Electrolysis Arrays for Offshore Wind Energy Hydrogen Production. [online] GTA Inc. Available at: <https://s23.a2zinc.net/clients/awea/owp2019/Custom/Handout/Speaker11671_Session5138_1.pdf> [Accessed 30 April 2020].
230 231
Refe
renc
es |
Febr
uary
202
0
Refe
renc
es |
Febr
uary
202
0
244 Ieee.org. (2018). Subsea Electrolyzers for Hydrogen and Oxygen Production. [online] IEEE. Available at: <https://site.ieee.org/tnc/event/subsea-electrolyzers-for-hydrogen-and-oxygen-production/> [Accessed 1 May 2020].
245 Lux Research, (2020). Evolution of Energy Networks: Decarbonizing the Global Energy Trade.
246 Lux Research, (2020). ‘Primary Research’.
247 Northerngasnetworks.co.uk. (2018). Hydrogen to heat homes: £14.9m for UK’s first trials on public gas network. [online] Northern Gas Networks. Available at: <https://www.northerngasnetworks.co.uk/2018/11/29/hydrogen-to-heat-homes-14-9m-for-uks-first-trials-on-public-gas-network/> [Accessed 3 May 2020].
248 Chiyodacorp.com. (2020). SPERA Hydrogen: Chiyoda’s Hydrogen Supply Business. [online] Chiyoda. Available at: <https://www.chiyodacorp.com/en/service/spera-hydrogen/> [Accessed 3 May 2020].
249 Greenammonia.org. (2020). Green Ammonia Consortium. [online] GAC. Available at: <https://greenammonia.org/index_eng.html> [Accessed 3 May 2020].
250 Lux Research, (2018). Siemens aims to demonstrate ammonia for energy storage applications.
251 Equinor.com. (2020). The world’s first carbon-free ammonia-fuelled supply vessel on the drawing board. [online] Equinor. Available at: <https://www.equinor.com/en/news/2020-01-23-viking-energy.html> [Accessed 4 May 2020].
252 Modisha, P. , Ouma, C., Garidzirai, R., Wasserscheid, P., and Bessarabov, D.. (2019) The Prospect of Hydrogen Storage Using Liquid Organic Hydrogen Carriers. [online] Energy & fuels. DOI: 10.1021/acs.energyfuels.9b00296
253 Hydrogeneurope.eu. (2020). Hydrogen transport & distribution. [online] Hydrogen Europe. Available at: <https://hydrogeneurope.eu/hydrogen-transport-distribution> [Accessed 30 April 2020].
254 Hydrogeneurope.eu. (2020). Liquefaction systems. [online] Hydrogen Europe. Available at: <https://hydrogeneurope.eu/liquefaction-systems> [Accessed 28 April 2020].
255 Irena.org. (2019). Hydrogen: a renewable perspective. [online] IRENA. Available at: <https://www.irena.org/-/media/Files/IRENA/Agency/Publication/2019/Sep/IRENA_Hydrogen_2019.pdf> [Accessed 28 April 2020].
256 Yin, L., and Ju, Y. (2019). Review on the design and optimization of hydrogen liquefaction processes. [online] Frontiers in Energy, doi: 10.1007/s11708-019-0657-4.
257 Cardella, U., Decker, L., and Klein, H. (2017). Economically viable large-scale hydrogen liquefaction. IOP Conference Series: Materials Science and Engineering, 171.
258 Global.kawasaki. (2019). World’s First Liquefied Hydrogen Carrier SUISO FRONTIER Launches Building an International Hydrogen Energy Supply Chain Aimed at Carbon-free Society. [online] Kawasaki. Available at: <https://global.kawasaki.com/en/corp/newsroom/news/detail/?f=20191211_3487> [Accessed 27 April 2020].
259 Norled.no. (2019). Partners receive PILOT-E support to develop liquid hydrogen supply chain for maritime applications in Norway. [online] NORLED. Available at: <https://www.norled.no/en/news/partners-receive-pilot-e-support-to-develop-liquid-hydrogen-supply-chain-for-maritime-applications-in-norway/> [Accessed 28 April 2020].
260 Garceau, N. M., Baik, J. H., Chang, M. L., Kim, S. Y., Oh, I., and Karng, S. W. (2015). Development of a small-scale hydrogenliquefaction system. International Journal of Hydrogen Energy, 40(35), p. 11872-11878.
261 Bmvi.de. (2007). CEP Progress Report 2002-2007. [online] CEP. Available at: <https://www.bmvi.de/SharedDocs/EN/Documents/VerkehrUndMobilitaet/cep-progress-report-2002-2007.pdf?__blob=publicationFile> [Accessed 1 May 2020].
262 Crotogino, F., Donadei, S., Bunger, U., and Landinger, H. (2010). Large-Scale Hydrogen Underground Storage for Securing Future Energy Supplies. 18th World Hydrogen Energy Conference 2010 (WHEC 2010), Julich.
263 Energy.ox.ac.uk. (2019). Hydrogen for energy storage. [online] UCL Institute for Sustainable Resources. Available at: <https://www.energy.ox.ac.uk/wordpress/wp-content/uploads/2019/10/Paul-Dodds-Hydrogen-for-energy-storage.pdf> [Accessed 3 May 2020].
264 Caglayan, D., Weber, N., Heinrichs, H. U., Linßen, J., Robinius, M., Kukla, P. A., and Stolten, D. (2019). Technical Potential of Salt Caverns for Hydrogen Storage in Europe. International Journal of Hydrogen Energy, doi: 10.1016/j.ijhydene.2019.12.161.
265 Amid, A., and Mignard, D. (2016). Seasonal storage of hydrogen in a depleted natural gas reservoir. International Journal of Hydrogen Energy, 41(12), doi: 10.1016/j.ijhydene.2016.02.036.
266 HyStorPor (2020). Project focus and outcomes. [online] The University of Edinburgh. Available at: < https://blogs.ed.ac.uk/hystorpor/project-focus-outcomes/>. [Accessed 28 April 2020]
267 Oilandgasuk.co.uk. (2015). Offshore Gas Turbines and Dry Low NOx Burners: an analysis of the Performance Improvements (PI) Limited Database. [online] Oil & Gas UK. Available at: <https://oilandgasuk.co.uk/wp-content/uploads/2015/05/producys-cayrgory.pdf> [Accessed 28 April 2020].
268 Ge.com. (2020). Hydrogen fueled gas turbines. [online] GE. Available at: <https://www.ge.com/power/gas/fuel-capability/hydrogen-fueled-gas-turbines> [Accessed 26 April 2020].
269 Ansaldoenergia.com. (2020). High hydrogen gas turbine retrofit to eliminate carbon emissions. [online] Ansaldo Energia. Available at: <https://www.ansaldoenergia.com/Pages/High-Hydrogen-Gas-Turbine-Retrofit-to-Eliminate-Carbon-Emissions.aspx> [Accessed 28 April 2020].
270 Rechargenews.com. (2020). World-first green hydrogen and storage plan to help turn Los Angeles 100%-renewable. [online] Recharge. Available at: <https://www.rechargenews.com/transition/world-first-green-hydrogen-and-storage-plan-to-help-turn-los-angeles-100-renewable/2-1-771614> [Accessed 5 May 2020].
271 New.siemens.com. (2020). This Swedish scientist works towards fulfilling Siemens’ 2030 hydrogen pledge. [online] Siemens. Available at: <https://new.siemens.com/global/en/company/stories/energy/hydrogen-capable-gas-turbine.html> [Accessed 4 May 2020].
272 Insideclimatenews.org. (2008). Technology roadmap: carbon capture and storage. [online] IEA. Available at: <https://insideclimatenews.org/sites/default/files/IEA-CCS%20Roadmap.pdf> [Accessed 3 May 2020].
273 Hydrogeneurope.eu. (2020). Liquefaction systems. [online] Hydrogen Europe. Available at: <https://hydrogeneurope.eu/liquefaction-systems> [Accessed 28 April 2020].
274 Inoue, K., Domen, S., Miyamoto, K., Tamura, I., Kawakami, T., and Tanimura, S. (2018). Development of Hydrogen and Natural Gas Co-firing Gas Turbine. [online] Mitsubishi Heavy Industries Technical Review, 55(2). Available at: <http://www.mhi.co.jp/technology/review/pdf/e552/e552160.pdf> [Accessed 3 MAy 2020].
275 Ge.com. (2019). Power to gas: Hydrogen for power generation. [online] GE. Available at: <https://www.ge.com/content/dam/gepower/global/en_US/documents/fuel-flexibility/GEA33861%20Power%20to%20Gas%20-%20Hydrogen%20for%20Power%20Generation.pdf> [Accessed 4 May 2020].
276 Windpowermonthly.com. (2020). Siemens launches ammonia storage demo. [online] Wind Power Monthly. Available at: <https://www.windpowermonthly.com/article/1486298/siemens-launches-ammonia-storage-demo> [Accessed 5 May 2020].
277 Valera-Medina, A., Gutesa, M., Xiao, H., Pugh, D., Giles, A., Goktepe, B., Marsh, R., Bowen, P. (2019). Premixed ammonia/hydrogen swirl combustion under rich fuel conditions for gas turbines operation [online]. Available at: <https://www.sciencedirect.com/science/article/abs/pii/S0360319919305907> [Accessed 4 May 2020].
278 Siemens, (2020). ‘Friday Thoughts’ [PowerPoint presentation], March 6, 2020, Aberdeen.
279 Valera-Medina, A., Gutesa, M., Xiao, H., Pugh, D., Giles, A., Goktepe, B., Marsh, R., and Bowen P. (2019). Premixed ammonia/hydrogen swirl combustion under rich fuel conditions for gas turbines operation. International Journal of Hydrogen Energy, 44(16), p. 8615-8626.
280 Tno.nl. (2016). Strategies towards an efficient future North Sea energy infrastructure. [online] TNO. Available at: <https://www.tno.nl/media/9413/sensei_strategies_towards_an_efficient_future_north_sea_energy_infrastructure.pdf> [Accessed 5 May 2020].
281 Prototech.no. (2020). Fuel Cell Power Systems. [online] Prototech. Available at: <https://www.prototech.no/applications/power-systems-fuel-cells/> [Accessed 4 May 2020].
282 The Press and Journal. World first for Aberdeen as city orders 15 double decker hydrogen buses. [online] The Press and Journal. Available at <https://www.pressandjournal.co.uk/fp/news/aberdeen/1799344/world-first-for-aberdeen-as-city-orders-15-double-decker-hydrogen-buses/> [Accessed 26 May 2020]
283 Lux Research, (2020). Fuel Cells Technology Page.
284 Hyseas (2020). Hyseas III. The Project. [online] Hyseas. Available at < https://www.hyseas3.eu/> [Accessed 26 May 2020]
285 Rivieramm.com. (2019). Hydrogen experts join offshore wind ‘electrolysis in the turbine’ study. [online] Riviera. Available at: <https://www.rivieramm.com/news-content-hub/news-content-hub/hydrogen-experts-join-offshore-wind-electrolysis-in-the-turbine-study-55446> [Accessed 3 May 2020].
286 Teledynees. (2020). Subsea Supercharger. [online] Teledyne. Available at: <http://www.teledynees.com/our-products/fuel-cell-products/subsea-supercharger> [Accessed 1 May 2020].
287 Cnbc.com. (2020). UK government announces millions in funding for ‘low carbon’ hydrogen production. [online] CNBC. Available at: <https://www.cnbc.com/2020/02/18/uk-government-announces-funding-for-low-carbon-hydrogen-production.html> [Accessed 27 April 2020].
288 Oedigital.com. (2019). A Blue/Green Energy Revolution. [online] Offshore Engineer. Available at: <https://www.oedigital.com/news/473907-a-blue-green-energy-revolution> [Accessed 28 April 2020].
289 Energyvoice.com. (2019). Offshore hydrogen production: Am I missing something? [online] Energy Voice. Available at: <https://www.energyvoice.com/opinion/213562/offshore-hydrogen-production-am-i-missing-something/> [Accessed 27 April 2020].
290 Ammoniaenergy.org. (2018). Ammonia Positioned for Key Role in Japan’s New Hydrogen Strategy. [online] Ammonia Energy Assocation. Available at: <https://www.ammoniaenergy.org/articles/ammonia-positioned-for-key-role-in-japans-new-hydrogen-strategy/> [Accessed 29 April 2020].
291 US National Research Council. (2008). Ammonia Acute Exposure Guideline Levels, Acute Exposure Guideline Levels for Selected Airborne Chemicals: Volume 6, [online]. Available at: <https://www.ncbi.nlm.nih.gov/books/NBK207883/> [Accessed 30 April 2020].
292 Linde-engineering.com. (2019). Hydrogen fuelling station with cryo pump technology. [online] Linde Engineering. Available at: <https://www.linde-engineering.com/en/images/DS_Cryo%20Pump_tcm19-523716.pdf> [Accessed 4 May 2020].
293 Tudelft.nl. (2018). Hydrogen: key to the energy transition. [online] TU Delft. Available at: <https://d1rkab7tlqy5f1.cloudfront.net/Websections/Powerweb/Lunch%20Lectures/Presentation%20Ad%20van%20Wijk%20Hydrogen%20key%20to%20the%20energy%20transition%20Powerweb%2014-6-2018.pdf> [Accessed 5 May 2020].
294 Globalccsinstitute.com. (2013). IEA 2013 CCS Roadmap. [online] Global CSS Institute. Available at: <https://www.globalccsinstitute.com/archive/hub/publications/109576/iea-2013-ccs-roadmap.pdf> [Accessed 2 April 2020].
295 Rochelle, G. T. (2009). Amine Scrubbing for CO2 Capture. Science, 325(5948), 1652–1654.
296 Lux Research, (2020). CO2 Capture Tech Page.
297 Nguyen, T., Tock, L., Breuhaus, P., Maréchal, F. and Elmegaard, B.(2016). CO2-mitigation options for the offshore oil and gas sector. Applied Energy, 161, p. 673-694.
298 Equinor.com (2020). Here’s how your CO2 emissions can be stored under the ocean. [online] Equinor. Available at: <https://www.equinor.com/en/magazine/carbon-capture-and-storage.html> [Accessed 15 April 2020].
299 Equinor.com (2020). Drilling for replenishment of Snøhvit gas. [online] Equinor. Available at: <https://www.equinor.com/en/news/drilling-replenishment-snohvit.html> [Accessed 25 April 2020].
300 Rufford, T., Smart, S., Watson, G., Graham, B., Boxall, J., Diniz da Costa, J. and May, E., (2012). The removal of CO2 and N2 from natural gas: A review of conventional and emerging process technologies. Journal of Petroleum Science and Engineering, [online] 94-95, p. 123-154. Available at: <https://www.sciencedirect.com/science/article/abs/pii/S0920410512001581> [Accessed 18 March 2020].
301 Lux Research carbon capture expert
302 IEA (2011). Technology roadmap - carbon capture and storage in industrial applications. [online] IEA. Available at: <https://www.iea.org/reports/technology-roadmap-carbon-capture-and-storage-in-industrial-applications> [Accessed 4 March 2020].
303 Zero Emissions Platform (2017). Future CCS Technologies Report. [online] ZEP. Available at: <https://zeroemissionsplatform.eu/wp-content/uploads/ZEP-Future-CCS-Technologies-report-12-January-20171.pdf> [Accessed 5 March 2020].
304 Khraisheh, M., Almomani, F. & Walker, G. (2020). Solid Sorbents as a Retrofit Technology for CO2 Removal from Natural Gas Under High Pressure and Temperature Conditions. Sci Rep 10, p. 269.
305 Fosbøl, P., Gaspar, J., Ehlers, S., Kather, A., Briot, P., Nienoord, M., Khakharia, P., Le Moullec, Y., Berglihn, O. and Kvamsdal, H. (2014). Benchmarking and Comparing First and Second Generation Post Combustion CO2 Capture Technologies. Energy Procedia, 63, p. 27-44.
306 Han, Y. and Ho, W. (2018). Recent advances in polymeric membranes for CO2 capture. Chinese Journal of Chemical Engineering, 26(11), p. 2238-2254.
307 Thechemicalengineer.com (2019). Aker Solutions to provide carbon capture technology to waste-to-energy plant (2019). [online] The Chemical Engineer. Available at: <https://www.thechemicalengineer.com/news/aker-solutions-to-provide-carbon-capture-technology-to-waste-to-energy-plant/> [Accessed 26 April 2020].
308 Peletiri, S., Rahmanian, N. and Mujtaba, I. (2018). CO2 Pipeline Design: A Review. Energies, 11(9), p.2184.
309 Global CCS Institute and IEAGHG. (2014). CO2 Pipeline Infrastructure January 2014. [online] Global CSS Institute and IEAGHG. Available at: <https://ieaghg.org/docs/General_Docs/Reports/2013-18.pdf> [Accessed 4 April 2020].
310 Barber, L., Liu, M., Spence, W., Hunen, K., and Lewis, J. (2020). ISO/TC 265 - Carbon Dioxide Capture, Transportation, And Geological Storage. [online] ISO. Available at: <https://www.iso.org/committee/648607.html> [Accessed 5 April 2020].
311 Zhang, Y., Wang, D., Yang, J., Adu, E., Shen, Q., Tian, L., Wu, L., and Shi, B. (2017). Correlative comparison of gas CO2 pipeline transportation and natural gas pipeline transportation. Modelling, Measurement and Control, 86, p. 63-75.
312 Serpa, J., Morbee, J. and Tzimas, E. (2011). Technical And Economic Characteristics Of A CO2 Transmission Pipeline Infrastructure. [online] EU JRC. Available at: <http://publications.europa.eu/resource/cellar/4ab1c4e2-398e-426c-b06f-1175d3c5a403.0001.02/DOC_1> [Accessed 24 March 2020].
313 Oosterkamp, A. and Ramsen, J. (2008). State-of-the-Art Overview of CO2 Pipeline Transport with Relevance to Offshore Pipelines. [online] PolyTec Norway University. Available at: <https://www.researchgate.net/publication/228688545_State-of-the-Art_Overview_of_CO_2_Pipeline_Transport_with_Relevance_to_Offshore_Pipelines> [Accessed 4 May 2020].
314 Wetenhall, B. Race, J. M., Downie, M. J. (2014). The Effect of CO2 Purity on the Development of Pipeline Networks for Carbon Capture and Storage Schemes. International Journal of Greenhouse Gas Control, [online] 30, p. 197–211. Available at: <https://www.sciencedirect.com/science/article/pii/S1750583614002771> [Accessed 4 May 2020].
315 DNVGL.com. (2020). CO2 Pipetrans. [online] DNV GL. Available at: <https://www.dnvgl.com/oilgas/joint-industry-projects/ongoing-jips/co2pipetrans.html> [Accessed 5 April 2020].
316 Acorn.com. (2018). The Acorn Options. [online] ACORN. Available at: <https://www.actacorn.eu/about-act-acorn/acorn-options> [Accessed 5 April 2020].
317 Acorn.com. (2018). D11 Infrastructure Reuse. [online] ACORN. Available at: <https://actacorn.eu/sites/default/files/ACT%20Acorn%20Infrastructure%20Re-use%20Report%201.0.pdf> [Accessed 2 April 2020].
318 OGTC Net Zero Taskforce member on ACORN steering committee
319 Element Energy. (2018). Shipping CO2 – UK Cost Estimation Study November 2018. [online] Element Energy. Available at: <https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/761762/BEIS_Shipping_CO2.pdf> [Accessed March 15, 2020].
320 Neele, F., de Kler, R., Nienoord, M., Brownsort, P., Koornneef, J., Belfroid, S., Peters, L., van Wijhe, A. and Loeve, D. (2017). CO2 Transport by Ship: The Way Forward in Europe. Energy Procedia, 114, p. 6824-6834.
321 SCCS. (2018). Ship transport of CO2 for Enhanced Oil Recovery – Literature Survey. [online] SCCS. Available at: <http://www.sccs.org.uk/images/expertise/reports/co2-eor-jip/SCCS-CO2-EOR-JIP-WP15-Shipping.pdf> [Accessed 5 April 2020].
322 Zero Emissions Platform. (2010). The Costs of CO2 Transport Post-demonstration CCS in the EU. [online] ZEP. Available at: <https://www.globalccsinstitute.com/archive/hub/publications/119811/costs-co2-transport-post-demonstration-ccs-eu.pdf> [Accessed 1 April 2020].
323 Northernlightssccs.com. (2020). Northern Lights Project. [online] Northern Lights SCCS. Available at: <https://northernlightsccs.eu/en/timeline> [Accessed 1 April 2020].
324 Raza, A., Gholami, R., Rezaee, R., Bing, C., Nagarajan, R. and Hamid, M. (2018). CO2 storage in depleted gas reservoirs: A study on the effect of residual gas saturation. Petroleum, 4(1), p. 95-107.
325 Wen, G. and Benson, S. (2019). CO2 plume migration and dissolution in layered reservoirs. International Journal of Greenhouse Gas Control, 87, p. 66-79.
326 Zhang, S., and DePaolo, D. J. (2017). Rates of CO2 mineralization in geological carbon storage. Acc. Chem. Res., 50, p. 2075–2084.
327 Jenkins, C. R., Cook, P. J., Ennis-King, J., Undershultz, J., Boreham, C., Dance, T., et al. (2012). Safe storage and effective monitoring of CO2 in depleted gas fields. Proc. Natl. Acad. Sci. U.S.A., 109(35–41).
328 Energy.gov. (2017). Accelerating the clean Energy Revolution. [online] US Department of Energy and Kingdom of Saudi Arabia Ministry of Energy, Industry, & Mineral Resources. Available at: <https://www.energy.gov/sites/prod/files/2018/05/f51/Accelerating%20Breakthrough%20Innovation%20in%20Carbon%20Capture%2C%20Utilization%2C%20and%20Storage%20_0.pdf> [Accessed 6 April 2020].
232 233
Refe
renc
es |
Febr
uary
202
0
Refe
renc
es |
Febr
uary
202
0
329 Aminu, M., Nabavi, S., Rochelle, C. and Manovic, V. (2017). A review of developments in carbon dioxide storage. Applied Energy, 208, p. 1389-1419.
330 Palebluedot.com. (2018). Progressing Development of the UK’s Strategic Carbon Dioxide Storage Resource. [online] Pale Blue Dot. Available at: <https://s3-eu-west-1.amazonaws.com/assets.eti.co.uk/legacyUploads/2016/04/D16-10113ETIS-WP6-Report-Publishable-Summary.pdf> [Accessed 27 April 2020].
331 Lux Research, (2019). CO2 Capture and Conversion: Innovative technology developers in the emerging CO2 capture and conversion space.
332 Lux Research, (2020). Enhanced Oil Recovery Tech Page.
333 Awan, A., Teigland, R., and Kleppe, J. (2008). A Survey of North Sea Enhanced-Oil-Recovery Projects Initiated During the Years 1975 to 2005. SPE Reservoir Evaluation & Engineering, 11, p. 497-512.
334 Offshoremag.com. (2020). BP Employs Lessons Learned For North Sea EOR Projects. [online] Offshore. Available at: <https://www.offshore-mag.com/production/article/16758510/bp-employs-lessons-learned-for-north-sea-eor-projects> [Accessed 4 May 2020].
335 Oil and Gas Authority UK. (2016). Enhanced Oil Recovery (EOR) Delivery Programme. [online]. Available at: <https://www.ogauthority.co.uk/media/3092/eor_delivery_programme.pdf> [Accessed 15 March 2020].
336 Offshoremag. (2020). Technical, Economic Constraints Hinder Widespread UK Offshore EOR Retrofits. [online] Offshore. Available at: <https://www.offshore-mag.com/field-development/article/16762087/technical-economic-constraints-hinder-widespread-uk-offshore-eor-retrofits> [Accessed 4 May 2020].
337 Global CCS Institute. (2019). Global status of CCS 2019 Targeting climate change. [online] Global CSS Institute. Available at: <https://www.globalccsinstitute.com/wp-content/uploads/2019/12/GCC_GLOBAL_STATUS_REPORT_2019.pdf> [Accessed 2 April 2020].
338 Ghanbari, S., Mackay, E. J., and Pickup, G. E. (2016). Comparison of CO2-EOR Performance between Offshore and Onshore Environments. Offshore Technology Conference Asia. doi:10.4043/26590-ms. Available at: <https://www.onepetro.org/conference-paper/OTC-26590-MS> [Accessed 4 May 2020]
339 Vox.com. (2020). Could Squeezing More Oil Out of the Ground Help Fight Climate Change? [online] Vox. Available at: <https://www.vox.com/energy-and-environment/2019/10/2/20838646/climate-change-carbon-capture-enhanced-oil-recovery-eor> [Accessed 4 May 2020].
340 Eide, L., Batum, M., Dixon, T., Elamin, Z., Graue, A., Hagen, S., Hovorka, S., Nazarian, B., Nøkleby, P., Olsen, G., Ringrose, P. and Vieira, R. (2019). Enabling Large-Scale Carbon Capture, Utilisation, and Storage (CCUS) Using Offshore Carbon Dioxide (CO2) Infrastructure Developments – A Review. Energies, 12(10), p.1945.
341 World Petroleum Council Comité Español. (2017). Offshore CO2 enhanced oil recovery with CCS programs. [online] Club Español de La Energie. Available at: <http://www.enerclub.es/file/39igbUIX1QN-8qvaUlEaug> [Accessed 14 March 2020].
342 Rosa, M. B., Cavalcante, J. S. de A., Miyakawa, T. M., & Freitas, L. C. S. de. (2018). The Giant Lula Field: World’s Largest Oil Production in Ultra-Deep Water Under a Fast-Track Development. Offshore Technology Conference. doi:10.4043/29043-MS
343 NordiCCS CO2. (2013). CO2 from Natural Gas Sweetening to KickStart EOR in the North Sea. [online] NordiCCS. Available at: <https://www.sintef.no/globalassets/sintef-energi/nordiccs/d1.1.1402-co2-form-natural-gas-sweetening-to-kick-start-eor-in-the-north-sea_web.pdf> [Accessed 20 March 2020].
344 Offshoremag.com. (2019). Digitalization provides opportunities and challenges. [online] Offshore. Available at: <https://www.offshore-mag.com/production/article/16763950/digitalization-provides-opportunities-and-challenges> [Accessed 2 May 2020].
345 Lux Research, (2018). The Digital Transformation of Power.
346 Lux Research, (2019). Key takeaways from PowerGen Asia 2019.
347 Lux Research, (2019). The Digital Transformation of Oil and Gas.
348 Sintef.no. (2020). Dynamic control of an electrolyser for voltage quality enhancement. [online] Sintef. Available at: <https://www.sintef.no/globalassets/project/nexpel/pdf/ipst11_id50_chiesa.pdf> [Accessed 2 May 2020].
349 Lux Research, (2018). Digitalization of Solar and Wind.
350 Offshoreenergy.biz. (2020). Digitalization Provides Opportunities and Challenges. [Online]. Available at< https://www.offshore-mag.com/production/article/16763950/digitalization-provides-opportunities-and-challenges>. [Accessed 2 May 2020].
351 ABB.com. (2020). Next Level oil, gas and chemicals Harnessing the power of digitalization to thrive in the ‘new normal’ of low oil prices. [online] ABB. Available at: <https://search.abb.com/library/Download.aspx?DocumentID=9AKK107045A4259&LanguageCode=en&DocumentPartId=&Action=Launch> [Accessed 3 May 2020].
352 SWZMaritime.nl. (2020). Digital Twinning of Floating Offshore Wind TurbineiIn Harsh Weather. [online] SWZ Maritime. Available at: <https://www.swzmaritime.nl/news/2019/09/24/digital-twinning-of-floating-offshore-wind-turbine-in-harsh-weather/?gdpr=deny> [Accessed 3 May 2020].
353 Framo.com. (2020). Aker BP Signs “Data Liberation Contract” With Framo. [online] Framo. Available at: https://www.framo.com/news/aker-bp-signs-data-liberation-contract/ [Accessed 3 May 2020].
354 Offshoreenergy.biz. (2020). Subsea Digitisation - Offshore Energy. [online] Available at: <https://www.offshore-energy.biz/subsea-digitisation/> [Accessed 3 May 2020].
355 Energyvoice.com. (2020). The Era of Oil and Gas Digitalisation is Upon Us - Woodmac - News for The Oil And Gas Sector. [online] Energy Voice. Available at: <https://www.energyvoice.com/opinion/202177/the-era-of-oil-and-gas-digitalisation-is-upon-us-woodmac/> [Accessed 3 May 2020].
356 Equinor.com. (2020). Digitalisation in our DNA. [online] Equinor. Available at: <https://www.equinor.com/en/how-and-why/digitalisation-in-our-dna.html> [Accessed 3 May 2020].
357 Equinor.com. (2017). Norway’s first platform to be remotely-operated from land. [online] Equinor. Available at: <https://www.equinor.com/en/news/09nov2017-valemon-remote.html> [Accessed 3 May 2020].
358 Offshoreenergy.biz. (2020). Production from Equinor’s First Unmanned Wellhead Platform To Start In September - Offshore Energy. [online] Offshore Energy. Available at: <https://www.offshore-energy.biz/production-from-equinors-first-unmanned-wellhead-platform-to-start-in-september/> [Accessed 3 May 2020].
359 Wood Mackenzie, (2020). Emissions Benchmarking Tool
360 UK Government. (2019) Technical note - Carbon Emissions Tax. [online]. Available at: <https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/828824/Carbon_Emissions_Tax_-_Technical_Note__1_.pdf> [Accessed 13 May 2020]
361 Oilandgasuk.co.uk. (2020). Economic Contributor. [online]. OGUK. Available at: <https://oilandgasuk.co.uk/economic-contribution/> [Accessed 13 May 2020]
362 Wood Mackenzie (2019). The Momentum of Floating Wind and its outlook Implications.
363 Offshore Renewable Energy Catapult (2018). An innovator’s guide to the offshore wind market. [online]. Available at: <https://ore.catapult.org.uk/app/uploads/2018/10/OREC01_7468-SME-Report-2-Offshore-Wind-Market-SP.pdf> [Accessed 13 May 2020]
364 UK Government (2020). Offshore wind Sector Deal. [online]. Available at: <https://www.gov.uk/government/publications/offshore-wind-sector-deal/offshore-wind-sector-deal> [Accessed 14 May 2020]
365 Ons.gov.uk. (2018). Low carbon and renewables energy economy, UK:2018. [online] Office for National Statistics Available at: <https://www.ons.gov.uk/economy/environmentalaccounts/bulletins/finalestimates/2018#exports-and-imports> [Accessed 14 May 2020]
366 RenewableUK.com (2019) Export Nation: UK Wind, Wave and Tidal Exports 2019 [online] Renewable UK Available at: <https://www.renewableuk.com/store/ViewProduct.aspx?ID=15152706> [Accessed 12 May 2020]
367 Wood Mackenzie (2019). The Momentum of Floating Wind and its outlook Implications.
368 Offshore Renewable Energy Catapult (2018). New report shows tidal stream and wave energy can pass UK government’s ‘triple test’ for emerging technology support [online] Available at: <https://ore.catapult.org.uk/press-releases/new-report-shows-tidal-stream-and-wave-energy-can-pass-uk-governments-triple-test-for-emerging-technology-support/> [Accessed 5 May 2020]
369 Uk Hydrogen and Fuel Cell Industry. (2012). Hydrogen and fuel cell industry: on track to deliver over 2,200 new jobs to the UK by 2020. [online] Available at: <http://www.ukhfca.co.uk/wp-content/uploads/Hydrogen-and-fuel-cell-industry.pdf> [Accessed 11 May 2020]
370 World Energy Council. (2018). Hydrogen-Industry as Catalyst. [online] Available at: <http://www.wereldenergieraad.nl/wp-content/uploads/2019/02/190207-WEC-brochure-2019-A4.pdf> [Accessed 11 May 2020]
371 Hydrogen Europe, 2018
372 Ukhfca.co.uk. (2020). The Industry. [online] UK Hydrogen and Fuel Cell Association. Available at: <http://www.ukhfca.co.uk/the-industry/> [Accessed 11 May 2020]
373 Global CCS Institute. (2020). The value of Carbon capture and storage (CCS). [online] Available at: <https://www.globalccsinstitute.com/wp-content/uploads/2020/05/Thought-Leadership-The-Value-of-CCS-2.pdf> [Accessed 11 May 2020]
374 Europa.eu. (2019). The potential for CCS and CCU in Europe. [online] IOGP. Available at: <https://ec.europa.eu/info/sites/info/files/iogp_-_report_-_ccs_ccu.pdf> [Accessed 11 May 2020]
375 Cen.acs.org. (2020). 45Q, the tax credit that’s luring US companies to capture CO2. [online] Chemical & Engineering News. Available at: <https://cen.acs.org/environment/greenhouse-gases/45Q-tax-credit-s-luring/98/i8> [Accessed 14 May 2020]
376 Global CCS Institute. (2019). The LCFS and CCS protocol: an overview for policymakers and project developers. [online] Available at: <https://www.globalccsinstitute.com/wp-content/uploads/2019/05/LCFS-and-CCS-Protocol_digital_version.pdf> [Accessed 11 May 2020]
377 Committee on Climate Change. (2019). Net Zero – Technical Report [Online]. Available at: <https://www.theccc.org.uk/publication/net-zero-technical-report/> [Accessed 21 April 2020]
378 Eti.co.uk. (2020). Strategic UK CCS Storage Appraisal. [online] Energy technolgies institute. Avaiable at: <https://www.eti.co.uk/programmes/carbon-capture-storage/strategic-uk-ccs-storage-appraisal> [Accessed 11 May 2020]
379 Vox.com. (2020). Can you really negate your carbon emissions? Carbon offsets, explained. [online] Vox. Available at: <https://www.vox.com/2020/2/27/20994118/carbon-offset-climate-change-net-zero-neutral-emissions> [Accessed 11 May 2020]
380 UKCCS Research Centre. (2020). [online] Available at: <https://ukccsrc.ac.uk/> [Accessed 11 May 2020]
381 European Comission. (2019) A European strategic long term vision for a prosperous, modern, competitive and climate neutral economy. [online] Available at: <https://ec.europa.eu/energy/sites/ener/files/documents/2_dgclima_rungemetzger.pdf> [Accessed 21 May 2020]
382 Europa.eu. (2019). A European Green Deal. [online] European Commission. Available at: <https://ec.europa.eu/info/strategy/priorities-2019-2024/european-green-deal_en> [Accessed 21 May 2020]
383 Europa.eu. (2020). [online] Available at: <https://ec.europa.eu/eurostat/cache/infographs/energy/bloc-4c.html> [Accessed 21 May 2020]
384 Worldbank.org. (2016). Renewable energy export-import: a win-win for the EU and North Africa. [online] World Bank blogs. Available at: <https://blogs.worldbank.org/energy/renewable-energy-export-import-win-win-eu-and-north-africa> [Accessed 21 May 2020]
385 Euractiv.com. (2020). Global hopes for hydrogen economy revived amid EU push. [online] Euractiv. Available at: <https://www.euractiv.com/section/energy-environment/news/global-hopes-for-hydrogen-economy-revived-amid-eu-push/> [Accessed 21 May 2020]
386 Enerdata.net. (2018). Electricity domestic consumption. [online] Enerdata. Available at: <https://yearbook.enerdata.net/electricity/electricity-domestic-consumption-data.html> [Accessed 21 May 2020]
387 Fuel Cells and Hydrogen 2 Joint Undertaking. (2019). Hydrogen Roadmap Europe. A sustainable pathway for the European energy transition. [online] Available at: <https://www.fch.europa.eu/sites/default/files/Hydrogen%20Roadmap%20Europe_Report.pdf> [Accessed 22 May 2020]
388 Econews.pt. (2020). Government approves hydrogen strategy, €7B investments. [online] Eco. Available at: <https://econews.pt/2020/05/22/government-approves-hydrogen-strategy-e7b-investments/> [Accessed 21 May 2020]
389 Europa.eu. (2020). Carbon Capture and Geologial Storage. [online] European Comission. Available at: <https://ec.europa.eu/clima/policies/innovation-fund/ccs_en> [Accessed 21 May 2020]
390 Ccsassociation.org. (2020). CCS in Europe. [online] Carbon Capture & Storage Association. Available at: <http://www.ccsassociation.org/new-about-ccs/proven-technology/> [Accessed 11 May 2020]
391 Eur-lex.europa.eu. (2019). Commission Delegated Regulation (EU) 2020/389. [online] European Commiossion. Available at: <https://eur-lex.europa.eu/legal-content/en/ALL/?uri=CELEX:32020R0389> [Accessed 11 May 2020]
392 Gov.uk. (2020). £90 million UK drive to reduce carbon emissions. [online] UK Government. Available at: <https://www.gov.uk/government/news/90-million-uk-drive-to-reduce-carbon-emissions> [Accessed 11 May 2020]
393 Ons.gov.uk. (2020). UK input-output analytical tables. [online] Office for National Statistics. Available at: <https://www.ons.gov.uk/economy/nationalaccounts/supplyandusetables/datasets/ukinputoutputanalyticaltablesdetailed> [Accessed 11 May 2020]
394 Gov.scot. (2019). Supply, Use and Input-Output Tables, 1998-2016. [online] Scottish Government. Available at: <https://www.gov.scot/publications/supply-use-input-output-tables-multipliers-scotland/> [Accessed 21 April 2020]
395 Oilandgasuk.co.uk. (2020) Roadmap 2035: A blueprint for net-zero. [online] OGUK. Available at: <https://oilandgasuk.co.uk/roadmap-2035/> [Accessed 21 April 2020]
396 Oil & Gas Authority. (2019). Projections of UK Oil and Gas Production and Expenditure. [online] Available at: <https://www.ogauthority.co.uk/media/5382/oga_projections-of-uk-oil-and-gas-production-and-expenditure.pdf> [Accessed 21 April 2020]
397 Nationalgrid.com. (2020). About us. [online] National Grid UK. Available at: <https://www.nationalgridgas.com/about-us> [Accessed 21 April 2020]
398 OGUK. (2019) Workforce Report 2019. [online] Available at: <https://oilandgasuk.cld.bz/Workforce-Report-2019> [Accessed 21 April 2020]
399 Office for National Statistics. (2018). Low carbon and renewable energy economy, UK:2018. [online] Available at: <https://www.ons.gov.uk/economy/environmentalaccounts/bulletins/finalestimates/2018#turnover-and-employment> [Accessed 21 April 2020]
400 Crown Estate Scotland, Offshore Renewable Energy Catapult. (2018). Macroeconomic benefits of floating offshore wind in the UK. [online] Available at: <https://www.crownestatescotland.com/maps-and-publications/download/219> [Accessed 21 April 2020]
401 Netzeroteesside.com. (2020). The UK’s first decarbonised industrial cluster. [online] Net Zero Teesside. Available at: <https://www.netzeroteesside.com/> [Accessed 21 April 2020]
402 Office for National Statistics. (2019). Type I UK employment multipliers and effects, reference year 2015. [online] Available at: <https://www.ons.gov.uk/economy/nationalaccounts/supplyandusetables/adhocs/009746typeiukemploymentmultiplier sandeffectsreferenceyear2015> [Accessed 21 April 2020]
403 Oil and Gas UK. (2020). Pathway to a Net-Zero Basin: Production Emissions Targets. [online] Available at: <https://oilandgasuk.co.uk/product/production-emissions-targets-report/> [Accessed 23 June 2020]
404 Wood Mackenzie. (2020). Decarbonising Norway’s upstream industry - is it profitable?
405 Gov.uk (2020). Greater Manchester to house to world’s largest liquid air battery. [Online]. Available at: <https://www.gov.uk/government/news/greater-manchester-to-house-to-worlds-largest-liquid-air-battery> [Accessed on 18 June 2020].
406 Oxfordmartin.ox.ac.uk. (2016). CO2 capture may be our only option for stabilising temperatures - we need to find out the costs, fast. [online]. Available at: <https://www.oxfordmartin.ox.ac.uk/blog/co2-capture-may-be-our-only-option-for-stabilising-temperatures-we-need-to-find-out-the-costs-fast/> [Accessed 4 June 2020]
407 The Oil & Gas Authority. (2020). UKCS Energy Integration. [online]. Available at:<https://www.ogauthority.co.uk/news-publications/publications/2020/ukcs-energy-integration-final-report/>[Accessed 20 August 2020].
234 235
Refe
renc
es |
Febr
uary
202
0
Refe
renc
es |
Febr
uary
202
0
Europe +44 131 243 4400Americas +1 713 470 1600Asia Pacific +65 6518 0800Email [email protected] www.woodmac.com
Wood Mackenzie™, a Verisk business, is a trusted intelligence provider, empowering decision-makers with unique insight on the world’s natural resources. We are a leading research and consultancy business for the global energy, power and renewables, subsurface, chemicals, and metals and mining industries. For more information visit: woodmac.com
WOOD MACKENZIE is a trademark of Wood Mackenzie Limited and is the subject of trademark registrations and/or applications in the European Community, the USA and other countries around the world.
DisclaimerThese materials, including any updates to them, are published by and remain subject to the copyright of the Wood Mackenzie group (“Wood Mackenzie”). Wood Mackenzie makes no warranty or representation about the accuracy or completeness of the information and data contained in these materials, which are provided ‘as is’. The opinions expressed in these materials are those of Wood Mackenzie, and nothing contained in them constitutes an offer to buy or to sell securities, or investment advice. Wood Mackenzie’s products do not provide a comprehensive analysis of the financial position or prospects of any company or entity and nothing in any such product should be taken as comment regarding the value of the securities of any entity. If, notwithstanding the foregoing, you or any other person relies upon these materials in any way, Wood Mackenzie does not accept, and hereby disclaims to the extent permitted by law, all liability for any loss and damage suffered arising in connection with such reliance.
Copyright © 2020, Wood Mackenzie Limited. All rights reserved. Wood Mackenzie is a Verisk business.